U.S. patent application number 17/156961 was filed with the patent office on 2021-07-01 for hydraulic fracture composition and method.
The applicant listed for this patent is AQUASMART ENTERPRISES, LLC. Invention is credited to Calder Hendrickson, Todd Naff, Tommy K. Thrash.
Application Number | 20210198562 17/156961 |
Document ID | / |
Family ID | 1000005449591 |
Filed Date | 2021-07-01 |
United States Patent
Application |
20210198562 |
Kind Code |
A1 |
Hendrickson; Calder ; et
al. |
July 1, 2021 |
HYDRAULIC FRACTURE COMPOSITION AND METHOD
Abstract
A method for improving the performance of fracturing processes
in oil production fields may rely on polymer coated particles
carried in the fracturing fluid. The particles may include heavy
substrates, such as sand, ceramic sand, or the like coated with
polymers selected to absorb water, increasing the area and volume
to travel more readily with the flow of fluid without settling out,
or allowing the substrate to settle out. Ultimately, the substrate
may become lodged in the fissures formed by the pressure or
hydraulic fracturing, resulting in propping open of the fissures
for improved productivity.
Inventors: |
Hendrickson; Calder;
(Lubbock, TX) ; Thrash; Tommy K.; (Lubbock,
TX) ; Naff; Todd; (Lubbock, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
AQUASMART ENTERPRISES, LLC |
Lubbock |
TX |
US |
|
|
Family ID: |
1000005449591 |
Appl. No.: |
17/156961 |
Filed: |
January 25, 2021 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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16390559 |
Apr 22, 2019 |
10899959 |
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17156961 |
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14171920 |
Feb 4, 2014 |
10266757 |
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16390559 |
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13418227 |
Mar 12, 2012 |
9057014 |
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14171920 |
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13299288 |
Nov 17, 2011 |
8661729 |
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13418227 |
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12789177 |
May 27, 2010 |
8341881 |
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13299288 |
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12324608 |
Nov 26, 2008 |
7726070 |
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12789177 |
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61012912 |
Dec 11, 2007 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 43/267 20130101;
C09K 8/805 20130101; A01N 25/34 20130101 |
International
Class: |
C09K 8/80 20060101
C09K008/80; A01N 25/34 20060101 A01N025/34 |
Claims
1. A method for forming proppant particles, the method comprising:
providing a substrate, constituted as granules discrete from one
another; providing a synthetic binder comprising a first volume of
polyacrylamide wetted with a solvent and absent any surfactant, and
a second volume of polyacrylamide in powdered form and absent any
surfactant; mixing the substrate granules with the synthetic binder
so that at least a portion of the substrate granules are at least
partly covered with the first volume of the synthetic binder;
coating the at least the portion of the substrate granules with the
second volume of the synthetic binder to form polymer-coated
substrate granules; and drying at least a portion of the synthetic
binder present on the polymer-coated substrate granules, wherein,
the polymer-coated substrate granules are able to flow in a carrier
fluid.
2. The method according to claim 1, further comprising: removing
from the polymer-coated substrate granules, in response to a
pre-determined condition, at least a portion of the second volume
of the synthetic binder.
3. The method according to claim 2, wherein the pre-determined
condition is selected from: an amount of water absorbed by the
second volume; a time of exposure of the synthetic binder to water;
a time of exposure of the second volume to water; an exposure of
the substrate granules to friction from a formation; an exposure of
the substrate granules to shear from the carrier fluid; and
exposure to a chemical.
4. The method according to claim 1, wherein the substrate granules
comprise sand.
5. The method according to claim 2, wherein the at least a portion
of the second volume is configured to form a gel when exposed to
water.
6. The method according to claim 3, wherein the at least a portion
of the second volume is configured to form a gel when exposed to
water.
7. The method according to claim 1, wherein the polymer-coated
substrate granules are dry and pourable prior to introduction into
the carrier fluid.
8. A method for forming proppant particles for use in a fissure,
the method comprising: providing a substrate, constituted as
granules discrete from one another and having a hardness
corresponding to that of a fissure; providing a synthetic binder
comprising a first volume of polyacrylamide wetted with a solvent
and absent any surfactant, and a second volume of a water-absorbing
polymer in powdered form and absent any surfactant; mixing the
substrate granules with the synthetic binder so that at least a
portion of the substrate granules are at least partly covered with
the first volume of the synthetic binder; coating the at least the
portion of the substrate granules with the second volume of the
synthetic binder to form polymer-coated substrate granules; drying
at least a portion of the synthetic binder present on the
polymer-coated substrate granules, wherein, the polymer-coated
substrate granules are able to flow into the fissure by way of a
carrier fluid and prop open the fissure; and removing from the
polymer-coated substrate granules, in response to a pre-determined
condition, at least a portion of the second volume of the synthetic
binder.
9. The method according to claim 8, wherein the pre-determined
condition is selected from: an amount of water absorbed by the
second volume; a time of exposure of the synthetic binder to water;
a time of exposure of the second volume to water; an exposure of
the substrate granules to friction from a formation; an exposure of
the substrate granules to shear from the carrier fluid; and
exposure to a chemical.
10. The method according to claim 9, wherein the water-absorbing
polymer comprises polyacrylate.
11. The method according to claim 9, wherein the substrate granules
comprise an organic substrate.
12. The method according to claim 9, wherein the substrate granules
comprise sand.
13. The method according to claim 9, wherein the at least a portion
of the second volume is configured to form a gel when exposed to
water.
14. The method according to claim 12, wherein the synthetic binder
is configured to adhere the at least a portion of the second volume
to at least a portion of the sand.
15. The method according to claim 8, wherein the polymer-coated
substrate granules are dry and pourable prior to introduction into
the carrier fluid.
16. A method for forming a polymer-coated substrate, the method
comprising: providing a substrate, constituted as granules discrete
from one another; providing a synthetic binder comprising a first
volume of polyacrylamide wetted with a solvent, and a second volume
of a water-absorbing polymer in powdered form; mixing the substrate
granules with the synthetic binder so that at least a portion of
the substrate granules are at least partly covered with the first
volume of the synthetic binder; coating the at least the portion of
the substrate granules with the second volume of the synthetic
binder to form polymer-coated substrate granules; drying at least a
portion of the synthetic binder present on the polymer-coated
substrate granules, wherein, the polymer-coated substrate granules
are able to flow in a carrier fluid; and removing from the
polymer-coated substrate granules, in response to a pre-determined
condition, at least a portion of the second volume of the synthetic
binder.
17. The method according to claim 16, wherein the pre-determined
condition is selected from: an amount of water absorbed by the
second volume; a time of exposure of the synthetic binder to water;
a time of exposure of the second volume to water; an exposure of
the substrate granules to friction; an exposure of the substrate
granules to shear from the carrier fluid; and exposure to a
chemical.
18. The method according to claim 16, wherein the polymer-coated
substrate granules are dry and pourable prior to introduction into
the carrier fluid.
19. The method according to claim 18, wherein the synthetic binder
is water-soluble and formed to have a thickness on the substrate
granules and a chemistry selected to complete at least one of:
dissolving during transport of the substrate granules through a
formation; releasing the substrate granules from suspension in the
carrier fluid to lodge in the formation in response to at least one
of dissolving of the synthetic binder, dissolving of the polymer
coating, and shearing of the polymer coating from the substrate
granules.
20. The method according to claim 16, wherein the synthetic binder
further comprises a third volume of a second polymer in powder form
selected from a friction reducer, a biocide, an oxygen scavenger, a
clay stabilizer, a scale inhibitor, and a gelling agent, and the
third volume is coated on the at least the portion of the substrate
granules in same manner and with the second volume.
Description
RELATED APPLICATIONS
[0001] This application: is a divisional of U.S. patent application
Ser. No. 16/390,559, filed Apr. 22, 2019; which is a divisional of
U.S. patent application Ser. No. 14/171,920, filed Feb. 4, 2014;
which is a continuation of U.S. patent application Ser. No.
13/418,227, filed Mar. 12, 2012; which is a continuation-in-part of
U.S. patent application Ser. No. 13/299,288, filed Nov. 17, 2011;
which is a continuation-in-part of U.S. patent application Ser. No.
12/789,177, filed May 27, 2010, now U.S. Pat. No. 8,341,881 issued
Jan. 1, 2013; which is a continuation of U.S. patent application
Ser. No. 12/324,608, filed on Nov. 26, 2008 now U.S. Pat. No.
7,726,070, issued Jun. 1, 2010; which claims the benefit of U.S.
Provisional Patent Application Ser. No. 61/012,912, filed Dec. 11,
2007; all of which are hereby incorporated by reference in their
entirety.
BACKGROUND
1. The Field of the Invention
[0002] This invention relates to oil field and oil well
development, and, more particularly, to novel systems and methods
for fracturing and propping fissures in oil-bearing formations to
increase productivity.
2. The Background Art
[0003] Oil well development has over one hundred years of extensive
engineering and chemical improvements. Various methods for
stimulating production of well bores associated with an oil
reservoir have been developed. For example, United States Patent
Application Publication US 2009/0065253 A1 by Suarez-Rivera et al.
and entitled "Method and System for Increasing Production of a
Reservoir" is incorporated herein by reference in its entirety and
provides a description of fracturing technology in order to
increase permeability of reservoirs. Moreover, various techniques
exist to further improve the fracture channels, such as by acid
etching as described in U.S. Pat. No. 3,943,060, issued Mar. 9,
1976 to Martin et al., which is likewise incorporated herein by
reference in its entirety.
[0004] In general, different types of processes require various
treatments. In general, well production can be improved by
fracturing formations. Fracturing is typically done by pumping a
formation full of a fluid, containing a large fraction of water,
and pressurizing that fluid in order to apply large surface forces
to parts of the formation. These large surface forces cause
stresses, and by virtue of the massive areas involved, can produce
extremely high forces and stresses in the rock formations.
Accordingly, the rock formations tend to shatter, increasing
porosity an providing space for the production oil to pass through
the formation toward the bore hole for extraction. However, as the
foregoing references describe, the chemistry is not simple, the
energy and time required for incorporation of various materials
into mixtures is time, money, energy, and other resource
intensive.
[0005] It would be an advance in the art if such properties as
viscosity, absorption, mixing, propping, and so forth could be
improved by an improved composition and method for
introduction.
BRIEF SUMMARY OF THE INVENTION
[0006] In view of the foregoing, in accordance with the invention
as embodied and broadly described herein, a method, apparatus, and
composition are disclosed in certain embodiments in accordance with
the present invention, as including a substrate that may be formed
of sand, rock product, ceramic sand, gravel, or other hard and
structurally strong materials, provided with a binder to
temporarily or permanently secure a hydrating polymer in proximity
to the substrated. When used herein any reference to sand or
proppant refers to any or all of these used in accordance with the
invention. In certain embodiments of a method in accordance with
the invention, a composition as described may be mixed directly
into drilling fluids, such as a fracturing fluid made up of water
and other additives.
[0007] By virtue of the increased surface area and weight provided
to the polymeric powders affixed to the substrate, the surface
area, and consequently the frictional drag, is greatly increased,
sweeping the material of the invention into a flow of fluid. This
greatly decreases the time required to absorb polymers into the
fluid.
[0008] In fact, rather than having to wait to have the polymers
thoroughly mixed, or absorb a full capacity of water, and thereby
flow properly with the drilling fluid or fracturing fluid, a
composition in accordance with the invention will sweep along with
the fluid immediately, with the weight of the substrate submerging
the polymer. Meanwhile, the cross sectional area presented results
in hydrodynamic drag sweeps the composition along with the
flow.
[0009] Meanwhile, over time, the polymeric powder adhered to the
substrate will absorb water, without the necessity for the time,
energy, temperature, mixing, and so forth that might otherwise be
required by surface mixing. Thus, the composition in accordance
with the invention is immediately transportable and flows, relying
on the drilling or fracturing fluid as its carrier.
[0010] Moreover, as the polymer tends to pick up more water, the
density of the granule of substrate and polymer powder becomes
closer to the density of water. Accordingly, the size increase and
the density change tend to drive the particles of the composition
even more homogeneously with the flowing fluid. Thus, the sand does
not settle out in various eddies, obstructions, and other locations
of low velocity. Rather, the sand continues to be carried with the
fluid, providing a double benefit. That is, the sand weight and
area helps to initially mix and drive the particles (granules) with
the fluid. Thereafter, the hydration of the polymer tends to
increase the surface area and reduce the density of the granule or
particle, tending to make the particles flow even better and more
homogeneously with the surrounding fluid.
[0011] Ultimately, as the particles (granules) of the composition
flow into fracture locations, they provide very small proppants as
the substrate, such as sand, becomes trapped and lodged at various
choke points. Nevertheless, because of the small size, the sand or
other substrate acting as a proppant, simply needs to provide an
offset, keeping fractured surfaces from collapsing back against one
another. By providing the small, strong points of separation, the
substrate provides a well distributed proppant, carried to maximum
extent that the fluids will travel, and deposited in various traps,
choke points, and the like.
[0012] The net saving in time, money, energy for heating and
pumping, and the like is significant. Meanwhile, various
technologies for reducing friction in the flow of fluid pumped into
bore holes and other formation spaces is described in several
patents, including U.S. Pat. No. 3,868,328, issued Feb. 25, 1975 to
Boothe et al. and directed to friction reducing compounds, as well
as U.S. Pat. No. 3,768,565, issued Oct. 30, 1973 to Persinski et
al. and directed to friction reducing, U.S. Patent Application
Publication US 2001/0245114 A1 by Gupta et al. directed to well
servicing fluid, and U.S. Patent Application Publication US
2008/0064614 A1 by Ahrenst et al. and directed to friction
reduction fluids, all described various techniques, materials,
methods, and apparatus for developing, implementing, and
benefitting from various well fluids. All the foregoing patent
application publications and patents are hereby incorporated by
reference.
[0013] Similarly, the development of various chemicals has been
ubiquitous in oil field development. For example, U.S. Pat. No.
3,442,803, issued May 6, 1969 to Hoover et al. is directed to
thickened friction reducers, discusses various chemical
compositions, and is also incorporated herein by reference in its
entirety.
[0014] In one embodiment of an apparatus, composition and method in
accordance with the invention, a method may be used for formation
fracturing. The formation may be in rock and within or near an oil
reservoir underground. One may select an oil field region having a
formation to be fractured. Fracturing may be sought to increase
production. By providing a bore into the formation and a pump, a
carrier material, typically comprising a liquid, and sometimes
other materials dissolved or carried therein may be pumped into the
formation through the bore.
[0015] The carrier as a liquid, or slurry comprising a liquid, or
otherwise containing a liquid may be driven by the pump to be
pressurized into the formation. However, the carrier may be
provided an additive formed as granules. Each granule may include a
substrate, such as a grain of sand, ceramic sand, crushed rock,
other rock products, or the like having bonded thereto many
particles (e.g. powder) formed from a polymer.
[0016] The polymer may be selected to have various properties,
including lubricity, water absorption, water solubility, or the
like. This hydrophilic polymer may be bonded permanently,
temporarily, or the like to secure to the substrate. Various
binders may be used alone or in combination. These may range from a
solvent (e.g., organic or water) simply softening the polymer
itself to bond it, to glues, sugars, molasses, and various other
saccharides, as well as other products, including starches, other
polymers, and so forth.
[0017] Thus, with some bonds, the polymer powder may be less
permanent or attached to have a bond that is less robust. Over
time, the polymer powder so attached may wear off, pull away, or
otherwise remove from the substrate into the carrier fluid, and may
even act as a viscous agent, lubricant, or the like in the
carrier.
[0018] The method may include introducing the additive directly
into the carrier. The more dense substrate will immediately
submerge the granules in the carrier at ambient conditions. Thus
heating, extensive mixing, waiting, and the like may be dispensed
with, as the granules typically will not float or resist mixing
once initial surface tension is broken.
[0019] Pumping the carrier toward the formation is possible
immediately. The carrier fluid carries the granules by the liquid
dragging against the substrate (with the particles of polymer
attached. The substrate's cross sectional area engages immediately
the surrounding liquid, dragging it into the carrier to flow
substantially immediately therewith.
[0020] Meanwhile, weighting, by the substrate of the polymer,
permits the granules to flow into and with the carrier
independently from absorption of any of the liquid into the
polymer. Nevertheless, over time, absorbing by the polymer a
portion of the liquid results in the polymer expanding and
providing by the polymer, lubricity to the carrier with respect to
the formation;
[0021] Creating fractures may be accomplished by pressurizing the
carrier in the formation. This creates fissures or fractures. Thus,
flowing of the carrier and particles throughout the fractures or
fissures in the formation results in lodging, by the particles,
within those fractures or fissures. Unable to re-align, adjacent
surfaces of rock, now fracture cannot close back together due to
propping open the fractures by the substrate granules lodging in
the fractures.
[0022] The substrate is best if selected from an inorganic
material, such as sand, ceramic sand, or other hard, strong, rock
product. The polymer may be selected from natural or synthetically
formulated polymers. For example polymers of at acrylic acid,
acrylate, and various amides are available. Polyacrylamide has been
demonstrated suitable for all properties discussed above.
[0023] In fracturing a rock formation, the method may include
providing an additive comprising a substrate formed as granules,
each having an exterior surface, particles formed of a hydrophilic
material, the particles being comminuted to a size smaller than the
size of the granules and having first and second sides comprising
surfaces. The granules may each be coated with the particles, the
particles being dry and bonded to the exterior surface by any
suitable binder, including the polymer softened with a solvent. The
particles are each secured by the first side to the granules, the
second side extending radially outward therefrom.
[0024] Upon identifying a reservoir, typically far underground from
thousands of feet to miles, perhaps, and extending in a formation
of rock, one needs to provide a bore into the formation. Providing
a carrier, comprising a liquid, and possibly other materials known
in the art, is for the purpose of fracturing the formation.
Introducing the additive directly into the liquid at ambient
conditions is possible, because the substrate weighs the granules
down, and there is no need for long mixing, heating or the like as
in addition of polymers directly to the carrier.
[0025] Thus, pumping may continue or begin immediately to move the
carrier and additive down the bore and toward the formation. This
results in exposing the second sides of the polymer powder
particles directly to the liquid during transit of the carrier and
additive toward and into the formation. The polymer particles thus
begin absorbing, a portion of the liquid, typically principally
water. Swelling of the polymer increases the size, effective
diameter, and cross-sectional area, thus increasing the fluid drag
on the granules.
[0026] Fracturing, typically by hydraulic pressure in the carrier
creates fissures in the formation by fracturing the rock pieces in
bending, or by layer separation, with tensile stresses breaking the
rock. The resulting fissures allow carrying, by the carrier, of the
granules into the fissures. However, fissures vary in size and
path, resulting in lodging of granules, within the fissures. The
granules do not settle out from the carrier, and thus may travel
far into the formation and every fissure. However, each time a
grain or granule is lodged like a chock stone, it obstructs the
ability of the adjacent rock surfaces to close back with one
another.
[0027] Thus, rather than the proppant (substrate) settling out
ineffectually, failing to prop open the fissures, the granules are
swept forcefully with the flow of the carrier wherever the carrier
can flow, until lodged. Meanwhile, the lubricity of the polymer
aids the granules, and thus the substrate from being slowed,
trapped, or settled out by the slow flowing boundary layer at the
solid wall bounding the flow.
[0028] In summary, weighting, by the substrate, sinks the polymer
into the carrier readily and independently from absorption of the
liquid into the polymer. Mixing, dissolving, and so forth are
unnecessary, as the substrate drags the polymer into the carrier,
and the carrier drags the granule along with it in its flow path.
Lubrication is provided by the polymer between the substrate of
each granule and adjacent solid walls of the bore, passages
previously existing in the formation, and the fissures formed by
fracturing. Any separating, by some of the powdered polymer
particles from the substrate, still reduces friction drag on
passage of the carrier and particles within the formation.
[0029] A composition for fracturing and propping a formation of
rock may include a fluid operating as a carrier to be pumped into a
rock formation, a substrate comprising granules of an inorganic
material, each granule having an outer surface and a size
characterized by a maximum dimension thereacross, and all the
granules together having an average maximum dimension corresponding
thereto. A polymer comprising a hydrophilic material selected to
absorb water in an amount greater than the weight thereof may be
bound to the substrate. The polymer is comminuted to particles,
each particle having a size characterized by a maximum dimension
thereacross.
[0030] All the polymer particles may be characterized by an average
maximum dimension, and an effective (e.g. hydraulic diameter). The
average maximum dimension of the particles is best if smaller,
preferably much smaller, than the average maximum dimension of the
granules.
[0031] The particles of the polymer, bound to the substrate, will
travel with it in the fluid. Particles of the polymer are thus
further directly exposed to water in the fluid during travel with
the fluid. The granules, flowing in the fluid, are carried by the
hydrodynamic drag of the fluid against the cross-sectional area of
the granules coated with the particles of the polymer. The polymer,
selected to expand by absorbing water directly from the fluid,
increases the area and drag, assisting distribution in the
formation by the carrier fluid. The polymer meanwhile operates as a
lubricant lubricating the motion of the substrate against the
formation during flow of the granules against solid surfaces in the
formation, bore, and fracture fissures.
[0032] The inorganic material, such as sand, ceramic sand, or the
like is typically sized to lodge in fissures formed in the
formation and has mechanical properties rendering it a proppant
capable of holding open fissures formed in the formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0033] The foregoing features of the present invention will become
more fully apparent from the following description and appended
claims, taken in conjunction with the accompanying drawings.
Understanding that these drawings depict only typical embodiments
of the invention and are, therefore, not to be considered limiting
of its scope, the invention will be described with additional
specificity and detail through use of the accompanying drawings in
which:
[0034] FIG. 1 is a schematic cross-sectional view of a material
including a substrate provided with a binder securing a hydrating
polymer thereto in accordance with the invention;
[0035] FIG. 2 is a schematic block diagram of one embodiment of a
process for formulating and producing fluid additive particles in
accordance with the invention;
[0036] FIG. 3 is a schematic diagram of the fluid-particle
interaction in an apparatus, composition, and method in accordance
with the invention;
[0037] FIG. 4 is a chart illustrating qualitatively the
relationship between volumetric increase over time at various
temperatures, illustrating the improved activation with minimum
mixing and temperature increase of particles in accordance with the
invention;
[0038] FIG. 5 is a schematic diagram illustrating one embodiment of
friction reducing by polymers used in compositions in accordance
with the invention;
[0039] FIG. 6 is a schematic diagram of the fracturing and proppant
action of particles in accordance with a method and composition
according to the invention; and
[0040] FIG. 7 is a schematic block diagram of a fracturing and
propping process using compositions and methods in accordance with
the invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0041] It will be readily understood that the components of the
present invention, as generally described and illustrated in the
drawings herein, could be arranged and designed in a wide variety
of different configurations. Thus, the following more detailed
description of the embodiments of the system and method of the
present invention, as represented in the drawings, is not intended
to limit the scope of the invention, as claimed, but is merely
representative of various embodiments of the invention. The
illustrated embodiments of the invention will be best understood by
reference to the drawings, wherein like parts are designated by
like numerals throughout.
[0042] Referring to FIG. 1, a material 10 in accordance with the
invention may include a substrate 12 formed of a suitable material
for placement in the vicinity of a fracture region. For example, a
substrate may be a particle of sand, ceramic sand, volcanic grit,
or other hard material. In some embodiments, a substrate may be
formed of organic or inorganic material. Nevertheless, it has been
found effective to use sand as a substrate 12 inasmuch as it is
submersible in water and will not float as many organic materials
will when dry. Likewise, the sand as substrate 12 is comminuted to
such a small size that interstices between individual grains of the
sand substrate 12 provide ample space and minimum distance for
water to surround each of the substrate 12 particles.
[0043] In the illustrated embodiment, a binder 14 may be
distributed as a comparatively thin layer on the surface of the
substrate 12. Typical materials for binders may include both
temporary and permanent binders 14. Permanent binders include many
polymers, natural and synthetic. Temporary binders may be
sugar-based or other water soluble materials. For example, corn
syrup, molasses, and the like may form temporary binders. In the
presence of water, such material may ultimately dissolve.
Nevetheless, so long as the substrate 12 is not turned, mixed, or
otherwise disturbed significantly, any other materials supported by
the binder 14 would not be expected to dislocate.
[0044] Otherwise, certain naturally or synthetically occurring
polymers may also be used as a binder 14. Lignicite may be used as
a binder 14. Lignicite is a byproduct of wood, and provides
material having good adhesive properties, and substantial
permanence as a binder 14 on a substrate 12. Any suitable insoluble
polymer may be used for more permanent binding.
[0045] Other polymers may be used to form a binder 14. For example,
various materials used as glues, including mucilage, gelatin, other
water soluble polymers including, for example, Elmer's.TM. glue,
and the like may also operate as binders 14 to bind materials to a
substrate 12.
[0046] In certain embodiments, the substrate 12 may be used in oil
fields as a substrate 12 for polymer additives to fracture fluids.
In other situations, the substrate 12 may be implemented as a
proppant.
[0047] Pigment 16 may be implemented in any of several manners. For
example, the substrate 12 may have pigment 16 applied prior to the
application of the binder 14. In alternative embodiments, the
pigment 16 may actually be included in the binder 14, which becomes
a pigmented coating on the substrate 12. In yet other embodiments,
the pigments 16 may be added to a hydration particle 18 either as a
pigment 16 mixed therein, or as a pigment 16 applied as a coating
thereto. Thus the location of the pigment 16 in the Figures is
schematic and may take alternative location or application
method.
[0048] Particles 18 of a hydrophilic polymer material may be bonded
to the substrate 12 by the binder 14. Particles may be sized to
substantially coat or periodically coat the substrate 12.
[0049] In certain embodiments, the hydrophilic material 18 may be a
powdered polymeric material 18 such as polyacrylamide or any of the
materials in the patent documents incorporated by reference. In
other embodiments, the particles 18 may actually be organic
material having capillary action to readily absorb and hold water.
In one presently contemplated embodiment of an apparatus in
accordance with the invention, the particles 18 may be powdered
polymeric material in a dehydrated state, and having a capacity to
absorb water, typically many times the weight (e.g., five to forty
times) of a particular particle 18.
[0050] The substrate 12, in certain embodiments, may be some form
of sand or grannular material. The sand will typically be cleaned
and washed to remove dust and organic material that may inhibit the
binder 14 from being effective. Likewise, the substrate 12 may be
sized of any suitable size. For example, sand particles may range
from much less than a millimeter in effective diameter or distance
thereacross to approximately two millimeters across. Very coarse
sands or ceramic sands may have even larger effective diameters.
Hydraulic diameter is effective diameter (four times the area
divided by the wetted perimeter). However, in one presently
contemplated embodiment, washed and dried sand such as is used in
construction, such as in concrete, has been found to be suitable.
Fine sands such as masonry sands tend to be smaller, and also can
function suitably in accordance with the invention.
[0051] Accordingly, the distance across each powder particle 18 may
be selected to provide an effective coating of powdered particles
18 on the substrate 12. In one presently contemplated embodiment,
the effective diameter of the particles 18 may be from about a 30
mesh size to about a 100 mesh size. For example, a sieve system for
classifying particles has various mesh sizes. A size of about 30
mesh, able to pass through a 30 mesh sieve, (i.e., about 0.6 mm)
has been found suitable. Likewise, powdering the particles 18 to a
size sufficiently small to pass through a 100 mesh (i.e., about
0.015 mm) sieve is also satisfactory. A mesh size of from about 50
mesh to about 75 mesh is an appropriate material to obtain
excellent adhesion of particles 18 in the binder 14, with a
suitable size of the particles 18 to absorb significant liquid at
the surface of the substrate 12.
[0052] As a practical matter, about half the volume of a container
containing a substrate 12 as particulate matter will be space,
interstices between the granules of the substrate 12. One advantage
of using materials such as sand as the substrate 12 is that a
coating of the particles 18 may provide a substantial volume of
water once the particles 18 are fully saturated. By contrast, where
the size of the particles 18 is too many orders of magnitude
smaller than the effective diameter or size of the substrate
particles 12, less of the space between the substrate particles 12
is effectively used for storing water. Thus, sand as a substrate 12
coated by particles 18 of a hydrophilic material such as a polymer
will provide substantial space between the substrate particles 12
to hold water-laden particles 18.
[0053] The diameter of the particles 18, or the effective diameter
thereof, is typically within about an order of magnitude (e.g.,
10.times.) smaller than the effective diameter of the particles of
the substrate 12. This order of magnitude may be changed. For
example, the order of magnitude difference less than about 1 order
of magnitude (i.e., 10.times.) may still be effective. Similarly,
an order of magnitude difference of 2 (i.e., 100.times.) may also
function.
[0054] However, with particles 18 too much smaller than an order of
magnitude smaller than the effective diameter of the substrate 12,
the interstitial space may not be as effectively used. Likewise,
with an effective diameter of particles 18 near or larger than
about 1 order of magnitude smaller than the size of the particles
of the substrate 12, binding may be less effective and the
particles 18 may interfere more with the substrate itself as well
as the flow of water through the interstitial spaces needed in
order to properly hydrate a material 10.
[0055] Referring to FIG. 2, an embodiment of a process for
formulating the material 10 may involve cleaning 22 the material of
the substrate 12. Likewise, the material of the substrate 12 may be
dried 24 to make it more effective in receiving a binder 14. The
material of the substrate 12 may then be blended 26.
[0056] One embodiment, a ribbon blender provides an effective
mechanism to perform continuous blending as the binder 14 is added
28. Other types of mixers, such as rotary mixers, and the like may
be used. However, a ribbon blender provides a blending 26 that is
effective to distribute binder 14 as it is added 28.
[0057] For example, if an individual particle of the substrate 12
receives too much binder 14, and thus begins to agglomerate with
other particles of the substrate 12, a ribbon binder will tend to
separate the particles as a natural consequences of its shearing
and drawing action during blending 26.
[0058] As the binder 14 is added 28 to the mixture being blended
26, the individual particles of the substrate 12 will be
substantially evenly coated. At this stage, the binder 14 may also
be heated in order to reduce its viscosity and improve blending.
Likewise, the material of the substrate 12 or the environment of
the blending 26 may be heated in order to improve the evenness of
the distribution of the binder 14 on the surfaces of the substrate
12 materials or particles 12.
[0059] Blending 26 of the binder 14 into the material of the
substrate 12 is complete when coating is substantially even, and
the texture of the material 10 has an ability to clump, yet is
easily crumbled and broken into individual particles. At that
point, addition 30 of the hydrophilic particles 18 may be
accomplished.
[0060] For example, adding 30 the particles 18 as a powder into the
blending 26 is a naturally stable process. Typically the particles
18 attach to the binder 14 of the substrate 12 particles, thus
removing from activity that location. Accordingly, other particles
18 rather than agglomerating with their own type of material will
continue to tumble in the blending 26 until exposed to a suitable
location of binder 14 of the substrate 12. Thus, the adding 30 of
the particles 18 or powder 18 of hydrophilic material will tend to
be a naturally stable process providing a substantially even
coating on all the particles of the substrate 12.
[0061] Just as marshmallows are dusted with corn starch, rendering
them no longer tacky with respect to one another, the material 10
formulated by the process 20 are dusted with particles 18 and will
pour freely. Accordingly, distribution 32 may be conducted in a
variety of ways and may include one or several processes. For
example, distribution may include marketing distribution from
packaging after completion of blending 26, shipping to distributers
and retailers, and purchase and application by users.
[0062] An important part of distribution 32 is the deployment of
the material 10. In one embodiment of an apparatus and method in
accordance with the invention, the material 10 may be poured, as if
it were simply sand 12 or other substrate 12 alone. Since the
powder 18 or particles 18 have substantially occupied the binder
14, the material 10 will not bind to itself, but will readily pour
as the initial substrate material 12 will.
[0063] The material 10 may typically include from about 1 percent
to about 20 percent of a hydrophilic material 18 or particles 18.
The particles 18 may be formed of a naturally occurring material,
such as a cellulose, gelatin, organic material, or the like.
[0064] In one embodiment, a synthetic gel, such as polyacrylamide
may be used for the particles 18, in a ratio of from about 1 to
about 20 percent particles 18 compared to the weight of the
substrate 12. In experiments, a range of from about 5 to about 10
percent has been found to be the most effective for the amount
particles 18.
[0065] Sizes of particles 18 may range from about 20 mesh to
smaller than 100 mesh. Particles 18 of from about 50 to about 75
mesh have been found most effective.
[0066] The binder 14 may typically be in the range of from about in
1/4 percent to about 3 percent of the weight of the substrate 12. A
range of from about 3/4 percent to about 11/2 percent has been
found to work best. That is, with a binder such as lignicite, 1/4
of 1 percent has been found not to provide as reliable binding of
particles 18 to the substrate 12. Meanwhile, a ratio of higher than
about 3 percent by weight of binder 14 to the amount of a substrate
12, such as sand, when using lignicite as the binder 14, tends to
provide too much agglomeration. The pouring ability of the material
10 is inhibited as well as the blending 26, due to agglomeration.
Other binders also operate, including several smaller molecules
that are water soluble. For example, glues, gelatins, sugars,
molasses, and the like may be used as a binder 14. Insoluble
binders are also useful and more permanent.
[0067] One substantial advantage for the material 10 in accordance
with the present invention is that the material remains flowable as
a sand-like material 10 into the fluids to be used in oil field
fracturing. Thus, handling and application is simple, and the
ability of granular material 10 to flow under and around small
interstices of fractures provides for a very effective
application.
[0068] Referring to FIG. 3, a formation 80 such as a reservoir area
of an oil may increase large and small flows 82 in passages 84
formed in the rock 86 of the formation 80. Typically, the flow 82
represented by arrows 82 indicating the development of flow at a
faster speed in center of a passage 84, and the lower velocity near
the wall 88 of the passage 84, illustrates the flow 82 of fluid in
the passage 84.
[0069] In the illustrated embodiment, the granules 10 or large
composite particles 10 or the materials 10 formed as a granulated
material 10, having the substrate 12 in the center column with the
polymer 18 adhered by a binder 12 on the outside thereof. This
material 10 may be added to a flow 82 being pumped into a formation
80. Initially, a particle 10 will have an effective diameter 90a.
In this condition, the particle 10 of material 10 is largely
dependent on the density of the substrate 12, which constitutes the
majority of its volume. Eventually, over time, with exposure to the
liquid 82 or flow 82 and the water of that flow 82, the polymer 18
will absorb water, increasing in its effective diameter 90b.
Ultimately, the polymer 18 or the polymer powder 18 will eventually
become fully hydrated, increasing many times its size, and
beginning to dominate the effective diameter 90c or hydraulic
diameter 90c of the particle 10.
[0070] Initially, the diameter 90a reflects the comparatively
smaller size and larger density of the particle 10 dominated by the
weigh of the substrate 12, such as sand, ceramic sand, or some
other hard and strong material. Ultimately, the diameter 90a or
effective diameter 90a is sufficient to provide fluid drag
according to fluid dynamic equations, drawing the particle 10 into
the flow 82.
[0071] Meanwhile, the increase in diameter 90b and the ultimate
effective diameter 90c result in reduction of the density of the
particle 10 as the polymer 18 absorbs more water, bringing the net
density of the particle 10 closer to the density of water.
Accordingly, the particles 10 flow with the water exactly in sync,
so to speak, rather than settling out as a bare substrate 12 would
do.
[0072] For example, in areas where eddies in the flow occur, such
as corners, crevices, walls, and the like, heavy materials having
higher density, such as sand and the like, normally will tend to
drift out of the flow, toward a wall 88, and ultimately will settle
out. Instead, by virtue of the large "sail" presented by the larger
diameter 90c of a fully hydrated polymer 18, each particle 10 stays
with the flow 82 in passage 84, providing much more effective
transport.
[0073] Referring to FIG. 4, a chart 92 illustrates a volume axis 94
representing the volume of a particle 10 or material 10 in
accordance with the invention. The volume axis 90 is displayed
orthogonally with respect to a time axis 96, representing the
passage of time of the particle 10 submerged in a carrier 82 or
flow 82 of fluid 82. Typically, at different temperatures,
illustrated by curves 98a-98e, with the temperature associated with
curve 98a being the coldest and the temperature associated with the
curve 98e being the hottest, one can visualize how heat added to a
fluid flow 82 tends to increase the chemical activity and thus the
rate of absorption of water into a polymer 18.
[0074] In an apparatus and method in accordance with the invention,
the particles 10 may be added directly to a flow 82, without
waiting for any significant time to absorb water into the polymer
18. Instead, the normal flow 82 will draw the particles 10 along in
a passage 84 while exposing each individual particle 10 to
surrounding fluid 82, thus promoting maximum rates of exposure and
increased rates of absorption. Accordingly, the volume 94
increases, representing an increase in the absorption of water into
the polymer 18.
[0075] In an apparatus and method in accordance with the invention,
the curve 98a is suitable because the entire travel within the well
bore, and within the formation 80 by the fluid 82 bearing the
particles 10 is permissible and available as absorption time. By
contrast, prior art systems rely on the increased temperature of
curve 98e in order to provide the time, temperature, and mixing to
work polymers into a flow 82 or liquid carrier 82.
[0076] Referring to FIG. 5, in one embodiment of an apparatus,
composition, and method in accordance with the invention, some of
the polymer 18 may eventually be scraped, sheared, or otherwise
removed from the particles 10. If bonded only by itself with a
water solvent, such a separation may be easier than if bonded by a
more durable polymer. Such a release may even be engineered, timed,
controlled by a solvent, or the like.
[0077] Thus, a certain amount of the polymer 18 may be released
from the granule 10 into the carrier fluid 82 to flow with the
fluid 82 and operate as a general friction reducer or provide its
other inherent properties to the carrier fluid 82. By an engineered
process of bonding and un-bonding, the polymer powder may be less
permanent or attached to have a bond that is less robust. Over
time, the polymer powder so attached may release, tear, wear off,
pull away, or otherwise remove from the substrate into the carrier
fluid to act as a viscosity agent, surfactant, lubricant, or the
like in the carrier, according to its known properties available
for modifying the carrier 82.
[0078] For example, a polymer 100 or polymer chain 100 may be
captured on a corner 102 defining a passage 84 into which a flow 82
will proceed. Accordingly, the corner 102 renders less of an
orifice on the passage 84 against entry of the flow 82 by virtue of
the friction reduction of the polymer 100 in the fluid, deposited
temporarily or permanently about a corner 102. Thus, other
particles 10 passing the corner 100 may shear off a portion of the
polymer 18 carried thereby or may rely on the presence of the
polymer 18 as a direct friction reducing agent on the particle 10
(granule) itself, permitting the particles 10 to pass more easily
with the flow 82 into the passage 84.
[0079] Referring to FIG. 6, the fracture process is described in
various literature, including U.S. Patent Application publication
US 2009/0065253 by Suarez-Rivera et al. incorporated herein by
reference. In a fracturing process, the pressure applied to a
formation 80 tends to force apart large expanses of rock. As a
result of that expansion of passages 84 in a rock formation 80, the
rock is stressed. Pressure pumped into the fluid 82 flowing in the
passages 84 within the formation 80 results in bending stresses,
tensile stresses, and so forth in the formation 80.
[0080] In FIG. 6, the forces 110 illustrated the effect of a large
pressure applied over a large area. Since pressure multiplied by
area equals force, applying an elevated hydraulic pressure to a
large surface of a rock 86 or rock segment 86 within a formation 80
results in tensile forces. Compressive forces will not tend to
break rock. However, a tensile force, which may be induced by
bending, expansion, or the like, results in fracture of the rock.
The fracture of the rock 86 thus results in condition shown in the
lower view, in which the passages 84 are mere fissures within the
rock 86.
[0081] The inset of FIG. 6 magnifies the fissures 84 or passages 84
formed in the rock 86 and immediately entered by the working fluid
82 being used for the fracture. Having the particles 10 formed
around substrates 12, the fluid 82 extends into each of the
fissures formed. Fissures 84 are simply passages 84. Some may be
large, others small. Proppants 10 trapped in a small location may
still maintain opened in another opening much larger elsewhere on
the rock 86. They may also collect and fill larger spaces,
eliminating the ability for rocks 86 to return to former
positions.
[0082] After fracturing rock 86 to form all of the fissures 84, the
fluid 82 will pass through the fissures, carrying particles 10,
which eventually collect in cavities or reach choke points. In the
absence of the particles 10, fissures 84 could close back up after
the fracturing water leaves. However, by containing the particles
10, the individual substrates 12 are themselves rock in the form of
sand, ceramic sand, or the like. Thus, a particle 10 need only
obstruct the ability of the fissure 84 to close, and it may "prop"
open the fissures 84 precluding the rock 86 or the pieces of rock
86 from settling back into alignment with one another.
[0083] Thus, the particles 10 both alone and in collected piles act
as proppants left behind by the fluid flow 82, by virtue of the
particles 10B captured. As a practical matter, it is only the
substrate 12 that acts as a proppant. The polymer 18 may eventually
be worn off but can easily be compressed, distorted, or cut.
Regardless, as the fissures 84 open, they are back filled and close
in at choke points and settling points collecting the substrate
12.
[0084] Referring to FIG. 7, a process 10 may include preparing 112
a fluid 82. Processing 114 other additives other than the particles
10 may be done according to any suitable methods, including prior
art processes. Adding 116 directly to the fluid 82, the particles
10 as described hereinabove, may be done in such a manner that the
operators need not wait for absorption or any other processes to
take place. Additional energy for elevating temperature is not
required, neither mixing or the like, other than adding 116
directly particles 10 in to the flow 82. The flow 82 will
immediately grab the particles 10 according the principles of fluid
dynamics in which fluid drag is dependent upon a shape factor of
the particle 10, the density of the fluid 82, the square of
velocity of the fluid, and so forth, as defined in engineering
fluid mechanics.
[0085] The fluid 82 now bearing the particles 10 would be
immediately pumped 118 into the formation 80 that is the reservoir
80 of 8 and oil field. Eventually, pressurizing 120 the reservoir
by pressurizing the fluid 82 results in creating 122 fractures 84
or fissures 84 within the formation 80 by breaking up the rock 86
of the formation 80. A fracture 84 with enough displacement may
make a site for material 10 to stagnate and collect.
[0086] Creating 122 fracture lines throughout the formation 80 is
followed by penetrating 124, by the particles 10 borne in the fluid
82 into the passages 84 or fissures 84 in the rock 86 of the
formation 80. Whenever the flow 82 of fluid 82 carries a particle
10 to a choke point 108 in a passage 84, as illustrated in FIG. 6,
a particle 10 will be lodged as illustrated in the inset of FIG. 6,
a particle 10 with its polymer 18 still secured and intact may be
lodged. Similarly, the substrate 12 may be lodged 126 and the
polymer 18 may stripped therefrom by the consequent or subsequent
flowing of material in the flow 82. Likewise, piles of stagnant
particles 10 may backfill spaces, precluding rock 86 settling back
in.
[0087] After the lodging 126 or propping 126 of the fissures 84 by
the substrate 12, in the particles 10, the passages 84 will remain
open. These fissures 84 may then be used tolater withdraw 128 the
fluid 82 from the formation 80. Thereafter, returning 130 the
formation 80 to production may occur in any manner suitable. For
example, heat may be added to the formation, liquid may be run
through the formation as a driver to push petroleum out, or the
like.
[0088] The present invention may be embodied in other specific
forms without departing from its spirit or essential
characteristics. The described embodiments are to be considered in
all respects only as illustrative, and not restrictive. The scope
of the invention is, therefore, indicated by the appended claims,
rather than by the foregoing description. All changes which come
within the meaning and range of equivalency of the claims are to be
embraced within their scope.
* * * * *