U.S. patent application number 14/518611 was filed with the patent office on 2016-04-21 for system and method of treating a subterranean formation.
The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Anna Dunaeva, Chad Kraemer, Bruno Lecerf, Dmitriy Usoltsev.
Application Number | 20160108713 14/518611 |
Document ID | / |
Family ID | 55748636 |
Filed Date | 2016-04-21 |
United States Patent
Application |
20160108713 |
Kind Code |
A1 |
Dunaeva; Anna ; et
al. |
April 21, 2016 |
SYSTEM AND METHOD OF TREATING A SUBTERRANEAN FORMATION
Abstract
A method and system for treating a subterranean formation,
relating to a diluted stream of carrier fibers, and a high-loading
stream of a diverting agent, and their use in a downhole diversion
operation.
Inventors: |
Dunaeva; Anna; (Houston,
TX) ; Lecerf; Bruno; (Houston, TX) ; Usoltsev;
Dmitriy; (Richmond, TX) ; Kraemer; Chad;
(Katy, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Family ID: |
55748636 |
Appl. No.: |
14/518611 |
Filed: |
October 20, 2014 |
Current U.S.
Class: |
166/280.2 |
Current CPC
Class: |
C09K 8/68 20130101; E21B
33/138 20130101; C09K 2208/08 20130101; C09K 8/80 20130101; E21B
43/267 20130101; E21B 43/261 20130101 |
International
Class: |
E21B 43/267 20060101
E21B043/267; E21B 43/16 20060101 E21B043/16; E21B 33/12 20060101
E21B033/12; E21B 43/24 20060101 E21B043/24 |
Claims
1. A treatment method, comprising: introducing a diluted stream,
comprising a non-bridging amount of carrier fibers in a low
viscosity carrier fluid, into a high pressure flow line; adding
proppant to the diluted stream to form a proppant-laden stream;
injecting the proppant-laden stream from the high pressure flow
line into a first fracture; introducing a high-loading stream,
comprising a diverting agent, into the high pressure flow line to
combine with the diluted stream to form a diversion slurry;
delivering the diversion slurry from the high pressure flow line to
the first fracture to divert fluid flow to a second fracture; and
injecting the proppant-laden stream from the high pressure flow
line into the second fracture.
2. The method of claim 1, wherein the diluted stream comprises from
1.2 to 12 g/L of the carrier fibers based on the total volume of
the diluted stream (from 10 to 100 ppt, pounds per thousand gallons
of carrier fluid).
3. The method of claim 1, wherein the high-loading stream comprises
a low viscosity carrier fluid and the diverting agent comprises
from 1.2 to 12 g/L (from 10 to 100 ppt) of bridging fibers based on
the total volume of the high-loading stream, and from 1.2 to 180
g/L (10 to 1500 ppt) of manufactured shape particles based on the
total volume of the high-loading stream.
4. The method of claim 1, comprising stopping the addition of the
proppant to the diluted stream during the introduction of the
high-loading stream into the high pressure flow line and delivery
of the diversion slurry for the diversion to the second
fracture.
5. The method of claim 1, comprising interrupting the addition of
the proppant to the diluted stream during delivery of the diversion
slurry to the first fracture and resuming the addition of the
proppant to the dilute stream for the injection of the
proppant-laden stream to the second fracture.
6. The method of claim 1, further comprising maintaining a
continuous fluid flow of the diluted stream to the high pressure
flow line from an end of the injection of the proppant-laden stream
to the first fracture, through the delivery of the diversion slurry
and to an initiation of the injection of the proppant-laden stream
to the first fracture.
7. The method of claim 1, further comprising injecting one or more
spacer stages to separate the proppant-laden stream injected into
the first fracture from the diversion slurry, to separate the
diversion slurry from the proppant-laden stream injected into the
second fracture, or both.
8. The method of claim 1, wherein the proppant-laden streams are
slickwater.
9. The method of claim 1, wherein the carrier fiber is dispersed in
the diluted stream in an amount effective to inhibit settling of
the proppant in the proppant-laden streams.
10. The method of claim 1, wherein the diluted stream comprises
equal to or less than 4.8 g/L of the carrier fibers based on the
total volume of the diluted stream (less than 40 ppt).
11. The method of claim 1, wherein the carrier fibers are crimped
staple fibers.
12. The method of claim 1, wherein the carrier fibers are crimped
staple fibers comprising from 1 to 10 crimps/cm of length, a crimp
angle from 45 to 160 degrees, an average extended length of fiber
of from 3 to 15 mm, a mean diameter of from 8 to 40 microns, or a
combination thereof.
13. The method of claim 1, wherein the carrier fibers are crimped
staple fibers comprising crimping equal to or less than 5 crimps/cm
of fiber length.
14. The method of claim 1, wherein the carrier fibers comprise
polyester.
15. The method of claim 1, wherein the carrier fibers comprise
polyester wherein the polyester undergoes hydrolysis at a low
temperature of less than 93.degree. C. as determined by heating 10
g of the fibers in 1 L deionized water until the pH of the water is
less than 3.
16. The method of claim 1, wherein the carrier fibers comprise
polyester wherein the polyester undergoes hydrolysis at a moderate
temperature of between 93.degree. C. and 149.degree. C. as
determined by heating 10 g of the fibers in 1 L deionized water
until the pH of the water is less than 3.
17. The method of claim 1, wherein the carrier fibers comprise
polyester wherein the polyester is selected from the group
consisting of polylactic acid, polyglycolic acid, copolymers of
lactic and glycolic acid, and combinations thereof.
18. The method of claim 1, wherein the carrier fiber is selected
from the group consisting of polylactic acid (PLA), polyglycolic
acid (PGA), polyethylene terephthalate (PET), polyester, polyamide,
polycaprolactam and polylactone, poly(butylene) succinate,
polydioxanone, glass, ceramics, carbon (including carbon-based
compounds), elements in metallic form, metal alloys, wool, basalt,
acrylic, polyethylene, polypropylene, novoloid resin, polyphenylene
sulfide, polyvinyl chloride, polyvinylidene chloride, polyurethane,
polyvinyl alcohol, polybenzimidazole,
polyhydroquinone-diimidazopyridine,
poly(p-phenylene-2,6-benzobisoxazole), rayon, cotton, cellulose and
other natural fibers, rubber, and combinations thereof.
19. The method according to claim 1, wherein the high-loading
stream is introduced into the high pressure flow line at about 5 to
about 10 bbl/min.
20. The method according to claim 1, wherein the diluted stream is
introduced into the high pressure flow line at about 25 to about
100 bbl/min.
21. The method according to claim 1, wherein the diversion slurry
is delivered to the first fracture at about 30 to about 100
bbl/min.
22. A treatment method, comprising: introducing a diluted stream,
comprising a non-bridging amount of carrier fibers, from a diluted
fluid device to a high pressure flow line; introducing a
high-loading stream, comprising a mix of bridging fibers and
manufactured shape particles, from a high-loading fluid device to
the high pressure flow line; combining the diluted stream and the
high-loading stream to form a diversion slurry; delivering the
diversion slurry from the high pressure flow line to a downhole
fluid flow feature to divert fluid flow from the downhole fluid
flow feature to an alternate flow path.
23. The method of claim 22, wherein the diluted stream comprises a
low viscosity carrier fluid having a viscosity less than 50 mPa-s
at a shear rate of 170 s.sup.-1 and a temperature of 25.degree. C.,
and from 1.2 to 12 g/L of the carrier fibers based on the total
volume of the diluted stream (from 10 to 100 ppt, pounds per
thousand gallons of carrier fluid).
24. The method of claim 22, wherein the high-loading stream
comprises a carrier fluid having a viscosity less than 50 mPa-s at
a shear rate of 170 s.sup.-1 and a temperature of 25.degree. C.,
from 1.2 to 12 g/L (from 10 to 100 ppt) of the bridging fibers
based on the total volume of the high-loading stream, and from 1.2
to 180 g/L (10 to 1500 ppt) of the manufactured shape particles
based on the total volume of the high-loading stream.
25. The method of claim 22, wherein the diversion slurry comprises
a carrier fluid having a viscosity less than 50 mPa-s at a shear
rate of 170 s.sup.-1 and a temperature of 25.degree. C., from 1.2
to 12 g/L (from 10 to 100 ppt) of the total combined carrier and
bridging fibers based on the total volume of the diversion slurry,
and from 1.2 to 60 g/L (10 to 500 ppt) of the manufactured shape
particles based on the total volume of the diversion slurry.
26. The method of claim 22, comprising forming a bridge from the
diversion slurry to bridge over the downhole feature.
27. The method of claim 22, comprising forming a plug from the
diversion slurry to plug the downhole feature.
28. The method of claim 22, further comprising establishing a flow
of the diluted stream into the downhole feature before delivering
the diversion slurry, and alternating from the flow of the diluted
stream to the diversion slurry.
29. The method of claim 22, further comprising maintaining a
continuous fluid flow, comprising establishing a pre-flow of at
least a portion of the diluted stream into the downhole feature
before delivering the diversion slurry, alternating from the flow
of the diluted stream to the diversion slurry, bridging or plugging
the downhole feature with the diversion slurry, alternating from
the diversion slurry to a post-flow of the diluted stream, and
establishing or increasing a fluid flow to the alternate flow
path.
30. The method of claim 22, wherein the diluted fluid device and
high-loading device are each pumps.
31. The method according to claim 22, wherein the high-loading
device is a ball injector.
32. A treatment method, comprising: injecting a treatment fluid
through a high pressure flow line into the subterranean formation
to form a hydraulic fracture system, wherein the treatment fluid
comprises: a low viscosity carrier fluid having a viscosity less
than 50 mPa-s at a shear rate of 170 s-1 and a temperature of
25.degree. C.; proppant dispersed in the carrier fluid; and carrier
fiber dispersed in the carrier fluid; maintaining a rate of the
injection of the treatment fluid to avoid bridging in the wellbore;
introducing a diluted stream, comprising a non-bridging amount of
the carrier fibers and optionally free of the proppant, to the high
pressure flow line; introducing a high-loading stream, comprising a
mix of bridging fibers and manufactured shape particles, to the
high pressure flow line; combining the diluted stream and the
high-loading stream to form a diversion slurry, delivering the
diversion slurry from the high pressure flow line to the hydraulic
fracture system to divert fluid flow from one fracture to
another.
33. A system for injecting a treatment fluid, comprising: at least
one diluted fluid device that transports a diluted stream to a high
pressure flow line; at least one high-loading device that
transports a high-loading stream to the high pressure flow line to
combine with the diluted stream to form a diversion slurry; and a
flow path for the diversion slurry to a downhole feature.
Description
BACKGROUND
[0001] The list of diverting techniques used in wellbores includes,
but is not limited to, mechanical isolation devices such as packers
and well bore plugs, bridge plugs, ball sealers, slurried solids
such as benzoic acid flakes and removable and/or degradable
particulates. For example, the hydraulic and acid fracturing of
horizontal wells as well as multi-layered formations frequently
require the use of diversion techniques to direct the fracturing
fluid between different zones.
[0002] Treatment diversion with particulates may be based on the
bridging of particles of the diverting material, e.g., behind
casing, and forming a plug by accumulating additional particles at
the formed bridge. Several problems are related to treatment
diversion with particulate materials. One problem is that a
precisely timed delivery of a relatively high concentration "pill"
for diversion in a relatively small volume of treatment fluid for a
very short period of time is difficult using standard surface
pumping and mixing equipment, that is designed to supply typically
low concentrations solids or proppants delivered in large fluid
volumes at relatively high flow rates and high pressures for
extended periods of time to deliver the proppant to the far reaches
of an extensive fracture network. For example, tons of proppant may
be delivered at 0.12-0.18 g/L, based on the volume of carrier fluid
(1-1.5 ppa or pounds of proppant added per gallon of carrier fluid)
over a period of several hours, whereas the diversion slurry may
require delivery, in less than a minute, orders of magnitude more
solids, e.g., about 10 g/L.
[0003] Additionally, any interruption of the continuous injection
of treatment fluid can result in proppant or other solids falling
out of suspension and possibly forming a bridge in an undesired
location, leading to a failure of the fracture operation and
prematurely terminating the fracturing treatment. Therefore, care
must be taken in making any changes to the treatment fluid so as to
avoid an undesirable interruption of pumping of the treatment fluid
in a continuous manner.
[0004] As another consideration, dilution of the diverting slurry
with other wellbore fluid during pumping, e.g., via interface
mixing, reduces the ability of the diverting slurry to form a
bridge and/or plug and effect diversion to another downhole flow
feature. The necessity of using relatively large amounts and/or
high concentrations of diverting materials to effect diversion
imposes economic and logistic constraints, as well as difficulties
with over-diversion to undesired downhole features and removal of
excessive diverting material. The poor stability of some diverting
agents during either pumping and/or the subsequent treatment stage
can lead to poor diversion efficiency.
[0005] It can be a challenge to achieve the relatively high content
of a diverting agent within a diversion slurry of treatment fluid,
that is generally used for plugging or diverting a downhole feature
with solid diverting materials to form temporary bridges or plugs,
such as a total amount of fibers and/or other shaped particles of
from about 2.4 g/L (20 lbs/1000 gal) to about 180 g/L (1500
lbs/1000 gal. The ability to add a briefly high concentration of
solid in a continuous manner for a short period of time with
traditional low concentration solid feeders, which are limited in
their feeding rates, as well as how quickly the feeding rate can be
adjusted, is difficult. Because the treatment fluid, including both
the fracturing fluid and the diversion slurry, is to be injected at
a high rate, typically 132 L/s (50 bbl/min) or more, and at a high
pressure, e.g., 6.9 MPa (1000 psi) to 140 MPa (20,000 psi) or more,
the rate of addition of the diverting agent should be substantial
enough to create a stream of high concentration solid material.
Solid material may be in the form of manufactured shapes such as
flakes, fibers and particles. The traditional methods of adding
solid material cannot easily achieve a rapid injection of high
concentrations of diverting agent so as to achieve a suitable
stream, and when such methods are repeated during the treatment of
the well, errors may be compounded.
SUMMARY
[0006] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter. The statements made merely provide information
relating to the present disclosure, and may describe some
embodiments illustrating the subject matter of this
application.
[0007] In aspects, methods for injecting a diverting composition
may include transporting a diluted fluid stream to a high pressure
flow line, transporting a high-loading stream to the high pressure
flow line, combining the diluted fluid stream and the high-loading
stream to form a diverting composition, and introducing the
diverting composition into the wellbore.
[0008] In further aspects, systems for injecting a diverting
composition are envisaged. The systems may include at least one
diluted fluid device that transports a diluted fluid stream to a
high pressure flow line, and at least one high-loading device that
transports a high-loading stream to the high pressure flow line.
The diluted fluid stream and the high-loading stream may be
combined to form a diverting composition, and the diverting
composition may be introduced into the wellbore.
[0009] In further aspects, methods are disclosed. The methods may
be for pumping a diverting composition. The methods may include
pumping a diluted fluid stream to a high pressure flow line,
pumping a high-loading stream to the high pressure flow line,
combining the diluted fluid stream and the high-loading stream to
form a diverting composition, and introducing the diverting
composition into the wellbore. The diluted fluid stream may include
a first amount of degradable fibers, a viscosifying agent and
water. The high-loading stream may include a second amount of
degradable fibers, particles, and water.
[0010] In yet further aspects, treatment methods may comprise
introducing a diluted stream, comprising a non-bridging amount of
carrier fibers in a low viscosity carrier fluid, into a high
pressure flow line; adding proppant to the diluted stream to form a
proppant-laden stream; injecting the proppant-laden stream from the
high pressure flow line into a first fracture; introducing a
high-loading stream, comprising a diverting agent, into the high
pressure flow line to combine with the diluted stream to form a
diversion slurry; delivering the diversion slurry from the high
pressure flow line to the first fracture to divert fluid flow to a
second fracture; and injecting the proppant-laden stream from the
high pressure flow line into the second fracture.
[0011] In still further aspects, treatment methods may comprise
introducing a diluted stream, comprising a non-bridging amount of
carrier fibers, from a diluted fluid device to a high pressure flow
line; introducing a high-loading stream, comprising a mix of
bridging fibers and manufactured shape particles, from a
high-loading fluid device to the high pressure flow line; combining
the diluted stream and the high-loading stream to form a diversion
slurry; and delivering the diversion slurry from the high pressure
flow line to a downhole fluid flow feature to divert fluid flow
from the downhole fluid flow feature to an alternate flow path.
[0012] Yet further aspects comprise treatment methods comprising
injecting a treatment fluid through a high pressure flow line into
the subterranean formation to form a hydraulic fracture system,
wherein the treatment fluid comprises: a low viscosity carrier
fluid having a viscosity less than 50 mPa-s at a shear rate of 170
s.sup.-1 and a temperature of 25.degree. C., proppant dispersed in
the carrier fluid, and carrier fiber dispersed in the carrier
fluid; maintaining a rate of the injection of the treatment fluid
to avoid bridging in the wellbore; introducing a diluted stream,
comprising a non-bridging amount of the carrier fibers and
optionally free of the proppant, to the high pressure flow line;
introducing a high-loading stream, comprising a mix of bridging
fibers and manufactured shape particles, to the high pressure flow
line; combining the diluted stream and the high-loading stream to
form a diversion slurry; delivering the diversion slurry from the
high pressure flow line to the hydraulic fracture system to divert
fluid flow from one fracture to another.
[0013] Aspects pertain to systems for injecting a treatment fluid,
comprising at least one diluted fluid device that transports a
diluted stream to a high pressure flow line; at least one
high-loading device that transports a high-loading stream to the
high pressure flow line to combine with the diluted stream to form
a diversion slurry; and a flow path for the diversion slurry to a
downhole feature.
[0014] In any of the foregoing and following aspects of the
disclosure, the diluted stream may comprise from 1.2 to 12 g/L of
the carrier fibers based on the total volume of the diluted stream
(from 10 to 100 ppt, pounds per thousand gallons of carrier
fluid).
[0015] In any of the foregoing and following aspects of the
disclosure, the high-loading stream may comprise a low viscosity
carrier fluid; and the diverting agent may comprise from 1.2 to 12
g/L (from 10 to 100 ppt) of bridging fibers based on the total
volume of the high-loading stream, and from 1.2 to 120 g/L (10 to
1000 ppt) of manufactured shape particles based on the total volume
of the high-loading stream.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] FIG. 1 shows a schematic representation of a treatment
configuration of the related art.
[0017] FIG. 2 shows a schematic representation of a treatment
configuration according to one or more embodiments herein.
[0018] FIG. 3 shows a diagram of a treatment configuration
according to one or more embodiments herein.
[0019] FIG. 4 shows a graphical representation of pressure changes
with respect to time according to one or more embodiments
herein.
[0020] FIG. 5A schematically illustrates a bridging test apparatus
according to embodiments.
[0021] FIG. 5B schematically illustrates an enlarged detail of the
slot design in the apparatus of FIG. 5A.
[0022] FIG. 6 schematically graphs the proppant settling in a
treatment fluid with various fibers.
[0023] FIG. 7 schematically graphs the effect of fiber loading on
proppant settling in a treatment fluid with crimped mid temperature
fibers.
[0024] FIG. 8 schematically graphs the effect of fiber loading on
proppant settling in a treatment fluid with crimped low temperature
fibers.
[0025] FIG. 9 schematically graphs the effect of fiber diameter on
proppant settling in a treatment fluid with crimped mid temperature
fibers.
[0026] FIG. 10 schematically graphs the effect of fiber diameter on
proppant settling in a treatment fluid with crimped low temperature
fibers.
[0027] FIG. 11 schematically graphs the effect of fiber length on
proppant settling in a treatment fluid with crimped mid temperature
fibers.
[0028] FIG. 12 schematically graphs the effect of fiber length on
proppant settling in a treatment fluid with crimped low temperature
fibers.
[0029] FIG. 13 schematically graphs the effect of crimp level on
proppant settling in a treatment fluid with crimped low temperature
fibers.
[0030] FIG. 14 schematically graphs the proppant settling in a
slickwater fluid with various fibers.
DETAILED DESCRIPTION
[0031] In the following description, numerous details are set forth
to provide an understanding of the present disclosure. However, it
may be understood by those skilled in the art that the methods of
the present disclosure may be practiced without these details and
that numerous variations or modifications from the described
embodiments may be possible.
[0032] At the outset, it should be noted that in the development of
any such actual embodiment, numerous implementation--specific
decisions may be made to achieve the developer's specific goals,
such as compliance with system related and business related
constraints, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort
might be complex and time consuming but would nevertheless be a
routine undertaking for those of ordinary skill in the art having
the benefit of this disclosure. In addition, the composition
used/disclosed herein can also comprise some components other than
those cited. In the summary and this detailed description, each
numerical value should be read once as modified by the term "about"
(unless already expressly so modified), and then read again as not
so modified unless otherwise indicated in context. Also, in the
summary and this detailed description, it should be understood that
a range listed or described as being useful, suitable, or the like,
is intended to include support for any conceivable sub-range within
the range at least because every point within the range, including
the end points, is to be considered as having been stated. For
example, "a range of from 1 to 10" is to be read as indicating each
possible number along the continuum between about 1 and about 10.
Furthermore, one or more of the data points in the present examples
may be combined together, or may be combined with one of the data
points in the specification to create a range, and thus include
each possible value or number within this range. Thus, (1) even if
numerous specific data points within the range are explicitly
identified, (2) even if reference is made to a few specific data
points within the range, or (3) even when no data points within the
range are explicitly identified, it is to be understood (i) that
the inventors appreciate and understand that any conceivable data
point within the range is to be considered to have been specified,
and (ii) that the inventors possessed knowledge of the entire
range, each conceivable sub-range within the range, and each
conceivable point within the range. Furthermore, the subject matter
of this application illustratively disclosed herein suitably may be
practiced in the absence of any element(s) that are not
specifically disclosed herein.
[0033] The following definitions are provided in order to aid those
skilled in the art in understanding the detailed description.
[0034] The term "wellbore" is a drilled hole or borehole, including
the openhole or uncased portion of the well that is drilled during
a treatment of a subterranean formation. The term "wellbore" does
not include the wellhead, or any other similar apparatus positioned
over the wellbore. The term "treatment" or "treating" refers to any
subterranean operation that uses a fluid in conjunction with a
desired function and/or for a desired purpose. The term "treatment"
or "treating" does not imply any particular action by the
fluid.
[0035] The term "injecting" describes the introduction of a new or
different element into a first element. In the context of this
application, injection of a fluid, solid or other compound may
occur by any form of physical introduction, including but not
limited to pumping.
[0036] The term "fracturing" refers to the process and methods of
breaking down a geological formation and creating a fracture, i.e.,
the geological formation around a well bore, in order to increase
production rates from a hydrocarbon reservoir. The fracturing
methods otherwise use techniques known in the art.
[0037] The term "matrix acidizing" refers to a process where
treatments of acid or other reactive chemicals are pumped into the
formation at a pressure below which a fracture can be created. The
matrix acidizing methods otherwise use techniques known in the
art.
[0038] In some embodiments herein, a treatment fluid comprises a
carrier fluid, and may optionally further comprise fibers and/or
fiber mixtures, proppant and/or other materials such as particles
other than fiber or proppant, dispersed in the carrier fluid. As
used herein, when not used in context relative to a higher
viscosity fluid, a "low viscosity" fluid, e.g., a low viscosity
carrier, refers to one having a viscosity less than 50 mPa-s at a
shear rate of 170 s.sup.-1 and a temperature of 25.degree. C. The
term "particulate" or "particle" refers to a solid 3-dimensional
object with maximal dimension less than 1 meter. Here, "dimension"
of the object refers to the distance between two arbitrary parallel
planes, each plane touching the surface of the object at least at
one point.
[0039] The carrier fluid may include water, fresh water, e.g.,
"slickwater," seawater, connate water or produced water. The
carrier fluid may also include hydratable gels (such as guars,
polysaccharides, xanthan, hydroxy-ethyl-cellulose (HEC), guar,
copolymers of polyacrylamide and their derivatives, e.g.,
acrylamido-methyl-propane sulfonate polymer (AMPS), or other
similar gels, or a viscoelastic surfactant system, e.g., a betaine,
or the like), a cross-linked hydratable gel, a viscosified acid
(such as a gel-based viscosified acid), an emulsified acid (such as
an oil outer phase emulsified acid), an energized fluid (such as an
N.sub.2 or CO.sub.2 based foam), and an oil-based fluid including a
gelled, foamed, or otherwise viscosified oil. The carrier fluid may
be a brine, and/or may include a brine. The carrier fluid may
include hydrochloric acid, hydrofluoric acid, ammonium bifluoride,
formic acid, acetic acid, lactic acid, glycolic acid, maleic acid,
tartaric acid, sulfamic acid, malic acid, citric acid,
methyl-sulfamic acid, chloro-acetic acid, an amino-poly-carboxylic
acid, 3-hydroxypropionic acid, a poly-amino-poly-carboxylic acid,
and/or a salt of any acid. In embodiments, the carrier fluid
includes a poly-amino-poly-carboxylic acid, such as a trisodium
hydroxyl-ethyl-ethylene-diamine triacetate, mono-ammonium salts of
hydroxyl-ethyl-ethylene-diamine triacetate, and/or mono-sodium
salts of hydroxyl-ethyl-ethylene-diamine tetra-acetate, or other
similar compositions. When a polymer is present in a low viscosity
carrier fluid, for example, in some embodiments it may be present
at a concentration below 1.92 g/L (16 ppt), e.g. from 0.12 g/L (1
ppt) to 1.8 g/L (15 ppt). When a viscoelastic surfactant is used in
a low viscosity carrier fluid, for example, in some embodiments it
may be used at a concentration below 10 ml/L, e.g. 2.5 ml/L to 5
ml/L.
[0040] The term "diluted stream (or fluid)" in one sense, in the
context of concentration or loading of a material(s) or type(s) of
material(s) relative to another stream, which other stream may be,
but not necessarily, referred to as a "high-loading stream," where
the loadings of the comparative streams may or may not be
specified, refers to the one of the streams having the lower
loading of the material under consideration. In another sense,
where the context does not indicate that a relative loading is to
be implied, the term "diluted stream" refers to a stream comprising
4.8 g/L (40 lbs/1000 gal) or less of the material(s) or type(s) of
material(s), e.g., carrier fibers, based on the total volume of the
diluted stream (fluid plus solids volume). In some embodiments, the
diluted stream may comprise or consist essentially of fibers that
are proppant-suspending and/or non-bridging.
[0041] Similarly, the term "high-loading stream (or fluid)" in the
context of concentration or loading of a material(s) or type(s) of
material(s) relative to another stream, which other stream may be,
but not necessarily, referred to as a "diluted stream," where the
loadings of the comparative streams may or may not be specified,
refers to the one of the streams having the higher loading of the
material under consideration. In another sense, where the context
does not indicate that a relative loading is to be implied, the
term "high-loading stream" refers to a stream comprising more than
4.8 g/L (40 lbs/1000 gal) of the material(s) or type(s) of
material(s), e.g., a mix of fibers and other particles optionally
including proppant, based on the total volume of the high-loading
stream (fluid plus solids volume).
[0042] According to some embodiments of the present disclosure,
different types of fibers may be used optionally at different
loadings to provide different functionalities, which may not
necessarily be mutually exclusive, to a particular treatment fluid
or stream. For example, the term "carrier fibers" refers to fibers
which are suitable at an appropriate loading for assisting in the
transport of proppant into a fracture, e.g., either during
initiation, propagation or branching of the fiber, whereas the term
"non-bridging fibers" refers to fibers which are suitable for use
in a carrier fluid at specified conditions and loadings generally
without forming a bridge in the flow path of interest. For example,
carrier fibers may be bridging or non-bridging. "Bridging fibers"
refers to fibers that do not have the non-bridging quality and/or
non-bridging fibers used a bridge-inducing loading rates.
[0043] In some embodiments, the treatment fluid comprises from 1.2
to 12 g/L of the carrier fibers based on the total volume of the
carrier fluid (from 10 to 100 ppt, pounds per thousand gallons of
carrier fluid), e.g., equal to or less than 4.8 g/L of the fibers
based on the total volume of the carrier fluid (equal to or less
than 40 ppt) or from 1.2 or 2.4 to 4.8 g/L of the fibers based on
the total volume of the carrier fluid (from 10 or 20 to 40
ppt).
[0044] In some embodiments, the carrier fibers, which may be
proppant-suspending and/or non-bridging, are crimped staple fibers.
In some embodiments, the crimped fibers comprise from 1 to 10
crimps/cm of length, a crimp angle from 45 to 160 degrees, an
average extended length of fiber of from 4 to 15 mm, and/or a mean
diameter of from 8 to 40 microns, or 8 to 12, or 8 to 10, or a
combination thereof. In some embodiments, the carrier fibers
comprise low crimping equal to or less than 5 crimps/cm of fiber
length, e.g., 1-5 crimps/cm.
[0045] Depending on the temperature that the treatment fluid will
encounter, especially at downhole conditions, the carrier fibers
may be chosen depending on their resistance or degradability at the
envisaged temperature. In the present disclosure, the terms "low
temperature fibers", "mid temperature fibers" and "high temperature
fibers" may be used to indicate the temperatures at which the
fibers may be used for delayed degradation, e.g., by hydrolysis, at
downhole conditions. Low temperatures are typically within the
range of from about 60.degree. C. (140.degree. F.) to about
93.degree. C. (200.degree. F.); mid temperatures typically from
about 94.degree. C. (201.degree. F.) to about 149.degree. C.
(300.degree. F.); and high temperatures typically about
149.5.degree. C. (301.degree. F.) and above, or from about
149.5.degree. C. (301.degree. F.) to about 204.degree. C.
(400.degree. F.).
[0046] In some embodiments, the carrier fibers comprise polyester.
In some embodiments, the polyester undergoes hydrolysis at a low
temperature of less than about 93.degree. C. as determined by
slowly heating 10 g of the fibers in 1 L deionized water until the
pH of the water is less than 3, and in some embodiments, the
polyester undergoes hydrolysis at a moderate temperature of between
about 93.degree. C. and 149.degree. C. as determined by slowly
heating 10 g of the fibers in 1 L deionized water until the pH of
the water is less than 3, and in some embodiments, the polyester
undergoes hydrolysis at a high temperature greater than 149.degree.
C., e.g., between about 149.5.degree. C. and 204.degree. C. In some
embodiments, the polyester is selected from the group consisting of
polylactic acid, polyglycolic acid, copolymers of lactic and
glycolic acid, and combinations thereof.
[0047] In some embodiments, the proppant-suspending and/or
non-bridging carrier fibers are selected from the group consisting
of polylactic acid (PLA), polyglycolic acid (PGA), polyethylene
terephthalate (PET), polyester, polyamide, polycaprolactam and
polylactone, poly(butylene) succinate, polydioxanone, nylon, glass,
ceramics, carbon (including carbon-based compounds), elements in
metallic form, metal alloys, wool, basalt, acrylic, polyethylene,
polypropylene, novoloid resin, polyphenylene sulfide, polyvinyl
chloride, polyvinylidene chloride, polyurethane, polyvinyl alcohol,
polybenzimidazole, polyhydroquinone-diimidazopyridine,
poly(p-phenylene-2,6-benzobisoxazole), rayon, cotton, cellulose and
other natural fibers, rubber, and combinations thereof.
[0048] In some embodiments, the treatment fluid, e.g., the diluted
stream, when proppant is present as in the initiation, propagation
or other fracture creation operation, comprises from 0.01 to 1 kg/L
of the proppant based on the total volume of the carrier fluid in
the treatment stream (from 0.1 to 8.3 ppa, pounds proppant added
per gallon of carrier fluid), e.g., from 0.048 to 0.6 kg/L of the
proppant based on the total volume of the carrier fluid in the
dilute stream (0.4 to 5 ppa), or from 0.12 to 0.48 kg/L of the
proppant based on the total volume of the carrier fluid in the
dilute stream (from 1 to 4 ppa), or from 0.12 to 0.18 kg/L of the
proppant based on the total volume of the carrier fluid in the
dilute stream (from 1 to 1.5 ppa). As used herein, proppant loading
is specified in weight of proppant added per volume of dilute
stream or other treatment, e.g., kg/L (ppa=pounds of proppant added
per gallon of carrier fluid). Other materials in the treatment
fluid are generally expressed in terms of g/L based on the total
volume of the treatment fluid (ppt=pounds of material per thousand
gallons of treatment fluid). Exemplary proppants include ceramic
proppant, sand, bauxite, glass beads, crushed nut shells, polymeric
proppant, rod shaped proppant, and mixtures thereof.
[0049] In some embodiments, a suitable carrier fiber can be
dispersed in the carrier in an amount effective to inhibit settling
of proppant, where proppant is present. This settling inhibition
may be evidenced, in some embodiments, for example, in a static
proppant settling test at 25.degree. C. for 90 minutes. The
proppant settling test in some embodiments involves placing the
fluid in a container such as a graduated cylinder and recording the
upper level of dispersed proppant in the fluid. The upper level of
dispersed proppant is recorded at periodic time intervals while
maintaining settling (quiescent) conditions. The proppant settling
fraction is calculated as:
Proppant settling = [ initial proppant level ( t = 0 ) ] - [ upper
proppant level at time n ] [ initial proppant level ( t = 0 ) ] - [
final proppant level ( t = .infin. ) ] ##EQU00001##
[0050] The carrier fiber inhibits proppant settling if the proppant
settling fraction for the fluid containing the proppant and carrier
fiber has a lower proppant settling fraction than the same fluid
without the carrier fiber and with the proppant only. In some
embodiments of the diluted stream containing proppant, the proppant
settling fraction of the diluted stream in the static proppant
settling test after 90 minutes is less than 50%, e.g., less than
40%.
[0051] In some embodiments, the carrier fiber is dispersed in the
diluted stream in an amount insufficient to cause bridging, e.g.,
as determined in a small slot test comprising passing the treatment
fluid comprising the carrier fluid and the carrier fiber without
proppant at 25.degree. C. through a bridging apparatus such as that
shown in FIGS. 5A and 5B comprising a 1.0-1 8 mm slot that is 15-16
mm wide and 65 mm long at a flow rate equal to 15 cm/s, or at a
flow rate equal to 10 cm/s.
[0052] In some embodiments the carrier fiber is dispersed in the
diluted stream comprising proppant in both an amount effective to
inhibit settling of the proppant and in an amount insufficient to
cause bridging, wherein settling and bridging are determined by
comparing proppant accumulation in a narrow fracture flow test
comprising pumping the treatment fluid at 25.degree. C. through a 2
mm slot measuring 3 m long by 0.5 m high for 60 seconds at a flow
velocity of 65 cm/s, or at a flow velocity of 20 cm/s, relative to
a reference fluid containing the carrier fluid and proppant only
without the carrier fiber. In the narrow fracture flow test, the
slot may be formed of flow cells with transparent windows to
observe proppant settling at the bottom of the cells. Proppant
settling is inhibited if testing of the fluid with the proppant and
carrier fiber results in measurably less proppant settling than the
same fluid and proppant mixture without the carrier fiber at the
same other testing conditions. Bridging is likewise observed in the
narrow fracture flow test as regions exhibiting a reduction of
fluid flow also resulting in proppant accumulation in the flow
cells.
[0053] In some embodiments the treatment fluid comprising the
diluted stream may include a fluid loss control agent, e.g., fine
solids less than 10 microns, or ultrafine solids less than 1
micron, or 30 nm to 1 micron. According to some embodiments, the
fine solids are fluid loss control agents such as .gamma.-alumina,
colloidal silica, CaCO.sub.3, SiO.sub.2, bentonite etc.; and may
comprise particulates with different shapes such as glass fibers,
flocs, flakes, films; and any combination thereof or the like.
Colloidal silica, for example, may function as an ultrafine solid
loss control agent, depending on the size of the micropores in the
formation, as well as a gellant and/or thickener in any associated
liquid or foam phase.
[0054] In some embodiments, e.g., where the diluted stream is used
to carry proppant or otherwise in fracture creation with or without
proppant, the carrier fluid comprises brine, e.g., sodium chloride,
potassium bromide, ammonium chloride, potassium choride,
tetramethyl ammonium chloride and the like, including combinations
thereof. In some embodiments the diluted stream may comprise oil,
including synthetic oils, e.g., in an oil based or invert emulsion
fluid.
[0055] In some embodiments, e.g., where the diluted stream is used
to carry proppant or otherwise in fracture creation with or without
proppant, the carrier fluid comprises a friction reducer, e.g., a
water soluble polymer. The diluted stream may additionally or
alternatively include, without limitation, clay stabilizers,
biocides, crosslinkers, breakers, corrosion inhibitors, temperature
stabilizers, surfactants, and/or proppant flowback control
additives. The diluted stream may further include a product formed
from degradation, hydrolysis, hydration, chemical reaction, or
other process that occur during preparation or operation.
[0056] In some embodiments, a method to treat a subterranean
formation penetrated by a wellbore, comprises injecting the
treatment fluid described herein, e.g., the diluted stream into the
subterranean formation to form a hydraulic fracture system, and
maintaining a rate of the injection to avoid bridging in the
wellbore, such as, for example, as determined in a bridging testing
apparatus without proppant.
[0057] In some embodiments, the method may comprise injecting a
pre-pad, pad, tail or flush stage or a combination thereof, which
may be, for example, the diluted stream described herein. In some
embodiments, the treatment fluid used in other aspects of the
method comprises the diluted stream described herein, optionally
including proppant and/or other additives described herein, in any
combination.
[0058] The diluted stream may be prepared using blenders, mixers
and the like as shown in FIGS. 1-3 discussed in more detail below,
using standard treatment fluid preparation equipment and well
circulation and/or injection equipment. In some embodiments, a
method is provided to inhibit proppant settling in a treatment
fluid circulated in a wellbore, wherein the diluted stream
comprises the proppant dispersed in a low viscosity carrier fluid.
The method comprises dispersing carrier fiber in the carrier fluid
in an amount effective to inhibit settling of the proppant, such
as, for example, as determined in the small slot test, and
maintaining a rate of the circulation to avoid bridging in the
wellbore, such as, for example, as determined in a bridging testing
apparatus without proppant and/or in the narrow fracture flow test.
In some embodiments, the treatment fluid further comprises a
friction reducer.
[0059] According to some embodiments, the proppant stage(s) may be
injected into a fracture system using any one of the available
proppant placement techniques, including heterogeneous proppant
placement techniques, wherein the low viscosity treatment fluid
herein is used in place of or in addition to any
proppant-containing treatment fluid, such as, for example, those
disclosed in U.S. Pat. No. 3,850,247; U.S. Pat. No. 5,330,005; U.S.
Pat. No. 7,044,220; U.S. Pat. No. 7,275,596; U.S. Pat. No.
7,281,581; U.S. Pat. No. 7,325,608; U.S. Pat. No. 7,380,601; U.S.
Pat. No. 7,581,590; U.S. Pat. No. 7,833,950; U.S. Pat. No.
8,061,424; U.S. Pat. No. 8,066,068; U.S. Pat. No. 8,167,043; U.S.
Pat. No. 8,230,925; U.S. Pat. No. 8,372,787; US 2008/0236832; US
2010/0263870; US 2010/0288495; US 2011/0240293; US 2012/0067581; US
2013/0134088; EP 1556458; WO 2007/086771; SPE 68854: Field Test of
a Novel Low Viscosity Fracturing Fluid in the Lost Hills Fields,
California; and SPE 91434: A Mechanical Methodology of Improved
Proppant Transport in Low-Viscosity Fluids: Application of a
Fiber-Assisted Transport Technique in East Texas; each of which is
hereby incorporated herein by reference in its entirety.
[0060] The term "diverting (or diversion) agent" refers to a
chemical or solid agent used alone or with another diverting
agent(s) used in well treatments, e.g., stimulation treatments, to
at least temporarily selectively control the rate of flow of a
treatment fluid, e.g., reduce or stop the flow rate, into a
downhole feature being treated, and may (and usually will), but not
necessarily, initiate, maintain or increase the rate of flow of the
same or a different treatment fluid to another downhole feature.
Diverting agents, also known as chemical or solid diverters,
function by creating a temporary blocking effect, e.g., either a
bridge or a plug, that may optionally be cleaned up following the
treatment, i.e., for diversion or for temporal zonal isolation as
disclosed in U.S. Patent Application Publication No. 2012/0285692
to Potapenko et al., which is hereby incorporated by reference in
its entirety. A "diverting (or diversion) composition" refers to a
composition comprising a diverting agent plus a carrier fluid; and
the term "diversion slurry" refers to a diverting agent flowably
dispersed in a fluid such as a gas, liquid, foam or energized
fluid. A "downhole feature" refers to any feature without
limitation through which fluid may flow or pass, including, but not
limited to, a formation matrix, screen or other porous media, or
surface thereof, fracture, formation void, vug, wormhole, fluid
loss zone, chamber, perforation, valve, opening, or a line, tubing
pipe or similar flow conduit, such as casing, tubing (including
coiled tubing), drill pipe, and including any annulus or space
between any of such structures, and any combinations thereof, or
the like.
[0061] The diversion composition may be made of blends of particles
or blends of particles and flakes, as examples. For example, the
diversion composition may comprise a non-bridging fiber, either
alone at a bridging concentration or in combination with another
specific bridging fiber and/or particulates. The size of the
largest particles or flakes in the blends according to embodiments
may be slightly smaller than the diameter of the perforation holes
in the zone or other downhole feature to isolate or divert.
[0062] According to embodiments, the size of the particles or
flakes in the blends may be larger than an average width of the
void intended to be closed or temporally isolated. The average
width of the void may be the smallest width of the void after the
perforation hole or another entry in such void, at 10 cm, at 20 cm,
at 30 cm, at 50 cm or at 500 cm (when going into the formation from
the wellbore). The void may be a perforation tunnel, hydraulic
fracture or wormhole. In some embodiments, the ratio between
particles and flakes in the blends may reduce permeability of the
formed plugs.
[0063] In some embodiments, the diverting agent includes removable
diverting materials which may be degradable material and/or
dissolvable material. A degradable material refers to a material
that will at least partially degrade (for example, by cleavage of a
chemical bond) within a desired period of time such that no
additional intervention is used to remove the plug. For example, at
least 30% of the removable material may degrade, such as at least
50%, or at least 75%. In some embodiments, 100% of the removable
material may degrade. The degradation of the removable material may
be triggered by a temperature change, and/or by chemical reaction
between the removable material and another reactant. Degradation
may include dissolution of the removable material.
[0064] Removable materials for use as the diverting agent may be in
any suitable shape: for example, powder, particulates, beads,
chips, or fibers. When the removable material is in the shape of
fibers, the fibers may have a length of from about 2 to about 25
mm, such as from about 3mm to about 20mm In some embodiments, the
fibers may have a linear mass density of about 0.111 dtex to about
22.2 dtex (about 0.1 to about 20 denier), such as about 0.167 to
about 6.67 dtex (about 0.15 to about 6 denier). Suitable fibers may
degrade under downhole conditions, which may include temperatures
as high as about 180.degree. C. (about 350.degree. F.) or more and
pressures as high as about 137.9 MPa (about 20,000 psi) or more, in
a duration that is suitable for the selected operation, from a
minimum duration of about 0.5, about 1, about 2 or about 3 hours up
to a maximum of about 24, about 12, about 10, about 8 or about 6
hours, or a range from any minimum duration to any maximum
duration.
[0065] The removable materials may be sensitive to the environment,
so dilution and precipitation properties should be taken into
account when selecting the appropriate removable material. The
removable material used as a sealer may survive in the formation or
wellbore for a sufficiently long duration (for example, about 3 to
about 6 hours). The duration should be long enough for wireline
services to perforate the next pay sand, subsequent fracturing
treatment(s) to be completed, and the fracture to close on the
proppant before it completely settles, providing an improved
fracture conductivity.
[0066] Further suitable removable materials and methods of use
thereof include those described in U.S. Patent Application
Publication Nos. 2006/0113077, 2008/0093073, and 2012/0181034, the
disclosures of which are incorporated by reference herein in their
entireties. Such materials include inorganic fibers, for example of
limestone or glass, but are more commonly polymers or co-polymers
of esters, amides, or other similar materials. They may be
partially hydrolyzed at non-backbone locations. Any such materials
that are removable (due in-part because the materials may, for
example, degrade and/or dissolve) at the appropriate time under the
encountered conditions may also be employed in the methods of the
present disclosure. For example, polyols containing three or more
hydroxyl groups may be used. Suitable polyols include polymeric
polyols that solubilizable upon heating, desalination or a
combination thereof, and contain hydroxyl-substituted carbon atoms
in a polymer chain spaced from adjacent hydroxyl-substituted carbon
atoms by at least one carbon atom in the polymer chain. The polyols
may be free of adjacent hydroxyl substituents. In some embodiments,
the polyols have a weight average molecular weight from about 5000
to about 500,000 Daltons or more, such as from about 10,000 to
about 200,000 Daltons.
[0067] Further examples of removable materials include
polyhdroxyalkanoates, polyamides, polycaprolactones,
polyhydroxybutyrates, polyethyleneterephthalates, polyvinyl
alcohols, polyethylene oxide (polyethylene glycol), polyvinyl
acetate, partially hydrolyzed polyvinyl acetate, and copolymers of
these materials. Polymers or co-polymers of esters, for example,
include substituted and unsubstituted lactide, glycolide,
polylactic acid, and polyglycolic acid. For example, suitable
removable materials for use as diverting agents include polylactide
acid; polycaprolactone; polyhydroxybutyrate; polyhydroxyvalerate;
polyethylene; polyhydroxyalkanoates, such as
poly[R-3-hydroxybutyrate],
poly[R-3-hydroxybutyrate-co-3-hydroxyvalerate],
poly[R-3-hydroxybutyrate-co-4-hydroxyvalerate], and the like;
starch-based polymers; polylactic acid and copolyesters;
polyglycolic acid and copolymers; aliphatic-aromatic polyesters,
such as poly(.epsilon.-caprolactone), polyethylene terephthalate,
polybutylene terephthalate, and the like; polyvinylpyrrolidone;
polysaccharides; polyvinylimidazole; polymethacrylic acid;
polyvinylamine; polyvinylpyridine; and proteins, such as gelatin,
wheat and maize gluten, cottonseed flour, whey proteins,
myofibrillar proteins, caseins, and the like. Polymers or
co-polymers of amides, for example, may include
polyacrylamides.
[0068] Removable materials, such as, for example, degradable and/or
dissolvable materials, may be used in the diverting agent at high
concentrations (such as from about 201bs/1000gal to about
10001bs/1000gal, or from about 401bs/1000gal to about
7501bs/1000gal) in order to form temporary plugs or bridges. The
removable material may also be used at concentrations at least 4.8
g/L (40 lbs/1,000 gal), at least 6 g/L (50 lbs/1,000 gal), or at
least 7.2 g/L (60 lbs/1,000 gal). The maximum concentrations of
these materials that can be used may depend on the surface addition
and blending equipment available.
[0069] Suitable removable diverting agents also include dissolvable
materials and meltable materials (both of which may also be capable
of degradation). A meltable material is a material that will
transition from a solid phase to a liquid phase upon exposure to an
adequate stimulus, which is generally temperature. A dissolvable
material (as opposed to a degradable material, which, for example,
may be a material that can (under some conditions) be broken in
smaller parts by a chemical process that results in the cleavage of
chemical bonds, such as hydrolysis) is a material that will
transition from a solid phase to a liquid phase upon exposure to an
appropriate solvent or solvent system (that is, it is soluble in
one or more solvent). The solvent may be the carrier fluid used for
fracturing the well, or the produced fluid (hydrocarbons) or
another fluid used during the treatment of the well. In some
embodiments, dissolution and degradation processes may both be
involved in the removal of the diverting agent.
[0070] Such removable materials, for example dissolvable, meltable
and/or degradable materials, may be in any shape: for example,
powder, particulates, beads, chips, or fibers. When such material
is in the shape of fibers, the fibers may have a length of about 2
to about 25 mm, such as from about 3mm to about 20mm. The fibers
may have any suitable denier value, such as a denier of about 0.1
to about 20, or about 0.15 to about 6.
[0071] Examples of suitable removable fiber materials include
polylactic acid
[0072] (PLA) and polyglycolide (PGA) fibers, glass fibers,
polyethylene terephthalate (PET) fibers, and the like.
[0073] In some embodiments, the diverting agent content may include
pre-processed fiber flocks, which represent solids entrapped inside
a fiber network.
[0074] The high-loading stream may have a higher loading of
materials than the diluted stream, and thus the diversion slurry
will have a loading proportional to the amounts of materials and
flow rates from each stream being combined. In the diversion
slurry, for example, the loading of any one or total amount of any
or all of the carrier fibers, bridging fibers, proppant and other
particulates, where each is present, in some embodiments may be in
the range of from about 2.4 g/L (20 lbs/1000 gal) to about 120 g/L
(1000 lbs/1000 gal), or from about 4.8 g/L (40 lbs/1000 gal) to
about 90 g/L (750 lbs/1000 gal), e.g., concentrations at least 4.8
g/L (40 lbs/1000 gal), at least 6 g/L (50 lbs/1000 gal), or at
least 7.2 g/L (60 lbs/1000 gal).
[0075] As shown in FIG. 1, a system for pumping a fluid may include
a pumping system 200 for pumping a fluid from a surface 118 of a
well 120 to a wellbore 122 during an oilfield operation. The
operation may be a hydraulic fracturing operation, and the fluid
may be a fracturing fluid. The pumping system 200 includes a
plurality of water tanks 221, which feed water to a gel maker 223.
The gel maker 223 combines water from the water tanks 221 with a
gelling agent so as to form a gel. The gel is then transported to a
blender 225 where it is mixed with a proppant from a proppant
feeder 227 to form a fracturing fluid.
[0076] The fracturing fluid is then pumped at a low pressure (such
as 0.41-0.82 MPa (60-120 pounds per square inch (psi)) from the
blender 225 to plunger pumps 201 via the line 212. Each plunger
pump 201 receives the fracturing fluid at a low pressure and
discharges it into a common manifold 210 (sometimes called a
missile trailer or missile) at a high pressure as shown by the
discharge lines 214. The common manifold 210 then directs the
fracturing fluid from the plunger pumps 201 to the wellbore 122 via
the line 215. A computerized control system 229 may be employed to
direct the entire pump system 200 for the duration of the
operation.
[0077] In such a system, each of the pumps 201 may be exposed to an
abrasive proppant of the fracturing fluid. Accordingly, according
to embodiments, a split stream configuration may be designed to
allow a fracturing fluid to be pumped into the wellbore.
[0078] In a split stream configuration, as disclosed in U.S. Pat.
No. 7,845,413 to Shampine et al., which is hereby incorporated by
reference in its entirety, a pump system can be operated whereby
the fluid that is pumped from a well surface to a wellbore is split
into a clean side containing primarily water as well as a dirty
side containing solids in a fluid carrier. In a fracturing
operation, the dirty side may contain a proppant in a fluid
carrier, and the clean side would not be exposed to abrasive
fluids.
[0079] In some embodiments, a split stream configuration is
designed to ultimately transport a diverting composition, which may
be a diverting slurry, into a wellbore. The diverting composition
may be used at some time during a treatment operation, including a
hydraulic fracturing or acid fracturing operation. The diverting
composition may be injected to partially or fully close a fracture
in a subterranean formation so as to perform a diversion
operation.
[0080] In embodiments, a method for injecting a diverting
composition into a subterranean formation may include a split
stream configuration. As can be seen in FIG. 2, the diverting
composition may be formed at a point prior to injection in the
wellbore.
[0081] FIG. 2 shows an injecting system 300 for injecting a
diverting fluid from a surface 118 of a well 120 to a wellbore 122
during an oilfield operation. The injection may occur by pumping or
by another form of introduction. The operation may be for a
diverting treatment to be performed at some point during a
fracturing or other treatment. The injecting system 300 includes a
plurality of water tanks 321, which feed water downstream. The
injecting system 300 also includes tank 323, which feeds a
viscosifying agent to a blender 325 where it may be mixed with an
amount of proppant from proppant tank 327 and an amount of solid to
form a diluted stream. In some embodiments, the solid may be in the
form of manufactured shapes, which may include degradable fibers,
particles, or a combination of the two.
[0082] The diluted stream is then pumped at a low pressure (such as
0.41-0.82 MPa (60-120 psi)) from the blender 325 to plunger pumps
301 via the diluted stream line DL. Each plunger pump 301 receives
the diverting fluid at a low pressure and discharges it into a
common manifold 310.
[0083] Additionally, an amount of water from the water tanks 321
may be combined with a gelling agent supplied by tank 323 so as to
form a gel. A diverting agent may be included with the gel at
diverting agent truck 313 so as to form a high-loading stream. In
some embodiments, the diverting agent may include an amount of
manufactured shapes, which may be in the form of fibers, particles
or flakes. The mixture of the manufactured shapes and the gel may
occur by a process such as batch mixing. The resultant mixture
formed as the high-loading stream may be in the form of a
slurry.
[0084] The high-loading stream may pass through the high-loading
stream line HL and reach the pumps 301' whereby the high-loading
stream will be mixed and then pumped into the common manifold 310
which may include or be directly or indirectly connected to a high
pressure flow line. The pumps 301' may be high-loading pumps. In
the common manifold, the high-loading stream and the diluted stream
may then be mixed to form a diverting composition. The common
manifold 310 may then direct the diverting composition from the
plunger pumps 201 to the wellbore 122 via the line 315. In
embodiments, the high-loading stream and the diluted stream may be
combined outside of the common manifold 310, such as downstream of
the manifold, which may be by connecting iron or by connecting the
high-loading streams and the diluted stream at the wellhead.
[0085] A computerized control system 329 may be employed to direct
the entire pump system 300 for the duration of the operation.
[0086] In embodiments, the pumps 301' may be high pressure pumps
such as positive displacement pumps, multi-stage centrifugal pumps
or combinations thereof. In some embodiments, the pumps 301' may be
devices capable of injecting a diverting agent in the form of a
ball. Thus, the pumps 301' may be ball injectors, as described in
WO 2013/085410 to Lecerf et al., which is hereby incorporated by
reference in its entirety. In embodiments where the pumps 301' are
ball injectors, the high-loading stream will include a ball-type
diverting agent. The pumps 301' may also be suitable for injected
destructible containers or containers carrying a fluid and intended
to be broken mechanically or otherwise at some point during or
after injection into a wellbore.
[0087] The following description relates to the high-loading
stream.
[0088] In embodiments, the components of the high-loading stream
other than the diverting agent are components of a carrier fluid.
The carrier fluid may include water, fresh water, seawater, connate
water or produced water. The carrier fluid may also include
hydratable gels (such as guars, polysaccharides, xanthan,
hydroxy-ethyl-cellulose, or other similar gels), a cross-linked
hydratable gel, a viscosified acid (such as a gel-based viscosified
acid), an emulsified acid (such as an oil outer phase emulsified
acid), an energized fluid (such as an N.sub.2 or CO.sub.2 based
foam), and an oil-based fluid including a gelled, foamed, or
otherwise viscosified oil.
[0089] The carrier fluid may be a brine, and/or may include a
brine. The carrier fluid may include hydrochloric acid,
hydrofluoric acid, ammonium bifluoride, formic acid, acetic acid,
lactic acid, glycolic acid, maleic acid, tartaric acid, sulfamic
acid, malic acid, citric acid, methyl-sulfamic acid, chloro-acetic
acid, an amino-poly-carboxylic acid, 3-hydroxypropionic acid, a
poly-amino-poly-carboxylic acid, and/or a salt of any acid. In
embodiments, the carrier fluid includes a
poly-amino-poly-carboxylic acid, such as a trisodium
hydroxyl-ethyl-ethylene-diamine triacetate, mono-ammonium salts of
hydroxyl-ethyl-ethylene-diamine triacetate, and/or mono-sodium
salts of hydroxyl-ethyl-ethylene-diamine tetra-acetate, or other
similar compositions.
[0090] The high-loading stream also contains a diverting agent
which may include degradable fibers of manufactured shapes at high
loading, generally more than 100lb/1000gal.
[0091] In embodiments, the manufactured shapes which may be used
may be round particles, such as, for example, particles having an
aspect ratio less than about 5, or less than about 3. The particles
may be of dimension which are optimized for plugging or diverting,
such as disclosed in Potapenko et al. Though some particles may be
round in embodiments, the particles may not have to be round. The
particles may include some round particles and some particles of
other shapes, or may include no round particles at all. In
embodiments where the particles include round particles and other
shapes, the particles of other shapes may be cubes, tetrahedrons,
octahedrons, plate-like shapes (flakes), oval etc.
[0092] Also, the particles can include sand, different types of
ceramics used for producing proppant, as well as aluminosilicates,
such as muscovite mica. In addition, the diverting agent may
include mixtures of fibers, sand, particles, film and other similar
components.
[0093] In embodiments where fibers are included in the high-loading
stream, the fibers may be any of inorganic or organic fibrous
materials and can be either degradable or stable at bottomhole
conditions. Embodiments may include fiber materials such as PLA and
PGA fibers, glass fibers, or PET fibers. In embodiments,
pre-processed fiber flocks representing solids entrapped inside the
fiber network may be included.
[0094] The diverting agent may include manufactured shapes that may
be made of a swellable material. The swellable materials may be any
materials that swell in the presence of hydrocarbons, water or
mixtures of thereof. In embodiments, these may include elastomers,
swellable resins, swellable polymers, or clays. The materials may
be one or more of x-linked polyacrylamides and polyacrylic acid
derivatives, smectite clay, bentonite, oil-swellable rubber,
water-swellable elastomers and mixtures of thereof.
[0095] The swellable materials can be in any form and size,
including grains, spheres, fibers, shaped particulates, beads, and
balls. The swellable materials may also be degradable or
dissolvable in the presence of acids, hydroxides, amines or other
reagents. Swelling time of the particles can be also controlled by
slowly dissolvable coatings, additives in the base fluid or in the
composition of the swellable material as well as by changing
temperature.
[0096] In embodiments, the diverting agent including the fibers and
swellable materials may be suspended in the carrier fluid.
[0097] In embodiments, the swellable materials may swell in the
plug so that a decrease in the plug conductivity results, which
will thereby reduce the rate of fluid penetration in the isolated
zone. Control of the plug permeability may be performed by
replacement of the fluid that surrounds the plug with the fluid
that causes shrinkage of the swelled particles. In embodiments
where polyacrylamide particles are used as swellable component and
initial swelling happens in a water-based fluid, then shrinkage of
the swelled particles may be caused by exposure to organic solvents
or brines with high salinity. Hydrocarbons can be also used to case
shrinkage of swelled bentonite grains.
[0098] Other swellable particles can be modified proppants
comprising a proppant particle and a hydrogel coating. The hydrogel
coating is applied to a surface of the proppant particle and
localizes on the surface to produce the modified proppant.
[0099] In some embodiments, the diverting agent may include
polylactide resin particles. The polylactide resin can be molded
into different shapes and sizes.
[0100] The following relates to the diluted stream.
[0101] The diluted stream may include a carrier fluid. The carrier
fluid may be the same, or may differ from the carrier fluid in the
high-loading stream. In embodiments, the diluted stream may include
a fluid with a lower viscosity than the fluid in the high-loading
stream, which can be obtained by using the same gelling agent as in
the high-loading stream, but in lesser quantity.
[0102] The diluted stream may contain manufactured shapes, or may
not carry any manufactured shape. In embodiments where manufactured
shapes are included, such shapes may be the same ones as in the
high-loading stream. In such embodiments, the shapes may be
included at a lower loading (e.g., a lower concentration) than the
shapes in the high-loading stream. Further, the manufactured shapes
in the diluted stream may be a shape of a smaller dimension than
those in the high-loading stream.
[0103] In embodiments, the high-loading stream may contain large
degradable particles of a diameter of 4 mesh to 10 mesh or larger.
The diluted stream may contain comparatively smaller degradable
particles, such as those of diameter 10 mesh to 100 mesh or
smaller. In embodiments, the particle size and distribution of
particles will be optimized when the high-loading and diluted
streams converge.
[0104] In embodiments, the diluted stream may contain a material of
a shape different than in the high-loading stream. The diluted
stream may contain fiber shapes while the high-loading stream may
contain particulate shapes, or vice versa. In embodiments, the
high-loading stream may contain a variety of shapes, while the
diluted stream contains less variety of shape. In some embodiments,
the high-loading stream may contain both fibers and particles,
while the diluted stream contains fibers. The diluted stream would
still contain a lower loading of manufactured shapes than the
high-loading stream, when expressed in weight of shaped particles
by volume of the stream.
[0105] In embodiments, the high-loading stream and the diluted
stream are injected into the common manifold at particular rates.
The high-loading stream may be injected at about 1 to about 20
bbl/min, or about 5 to about 10 bbl/min, or about 7 bbl/min The
diluted stream may be injected at about 1 to about 100 bbl/min, or
about 25 to about 100 bbl/min, or about 25 to about 65 bbl/min, or
about 43 bbl/min. The total injection rate at the manifold and
subsequently into the wellbore will thus be about 2 to about 120
bbl/min, or about 30 to about 100 bbl/min, or about 30 to about 75
bbl/min, or about 50 bbl/min
[0106] Then, to complete the operation, a cleaning operation may be
performed.
[0107] This can include pumping an amount of fiber to clean the
lines, then stopping pumping fiber, and then, once the last
fraction of proppant has passed the perforations, slowing down the
injection rate when squeezing particles through the
perforations.
[0108] The following example describes a treatment utilizing a
diverting composition and method according to one or more
embodiments.
[0109] A horizontal well is being fractured in sections, with
sections delimited by bridge plugs. Each section is 91.4 m (300 ft)
long and has 6 0.305 m (1 ft) perforation clusters, separated by
15.2 m (50 ft). Each perforation cluster contains six perforations.
The section is being treated with two stages of 36,300 kg (80,000)
lbs of proppant, and each stage is separated by injecting a
diverting agent which is a mixture of manufactured shapes. The
shapes include particles and beads of various size and fibers.
[0110] A diverting agent (also referred to as a plugging or
diverting pill) in this example includes 22.7 kg (50 lbs) of
particles and includes 3.8 kg (8.4 lbs) of fibers in 795 L (5 bbl)
of 3 g/L (25 ppt) linear gel. This corresponds to 11.3 g/L (238
ppt) of particles and 0.48 g/L (40 ppt) of bridging fiber. The
high-loading stream is injected into the line connecting the
manifold to the wellhead (i.e., downstream of the manifold,
identified as line 315 in FIG. 2) at about 1100-1300 L/min (about
7-8 bbl/min) while the diluted stream is injected at about
6700-6800 L/min (42-43 bbl/min) to bring the total injection rate
to 7950 L/min (50 bbl/min) The diversion slurry derived as a result
of the combination of the high-loading stream and the diluted
stream has a volume of 1500 L (36 bbl), a particle loading of 4 g/L
(33.3 ppt), and a total fiber (carrier and bridging) loading of 6
g/L (50 ppt).
[0111] The high-loading stream is prepared in a mixing tub of a
cement mixing/blender float. Thirty minutes before the last
fraction of proppant enters the wellbore, diverting material is
added in the batch mixer. Specifically, the mixing tub is filled
with 795 L (5 bbl) of water gelled with 11.3 kg (25 lbs) of linear
gel. Into this 3.8 kg (8.4 lbs) of fiber are mixed. Then, 22.7 kg
(50 lbs) of a particulate blend are added to achieve a desired
concentration, and the stream is then mixed.
[0112] To pump the diverting agent in the high-loading stream, once
the last fraction of proppant has passed the pump, the proppant is
cut and 3180 L (20 bbl) of crosslinked fluid is injected. Then, the
crosslinker is cut and 3180 L (20 bbl) of linear gel is
injected.
[0113] To prepare the diluted stream, at a pod blender (which is
disposed at a low pressure side of the diluted stream), a dry
additive feeder may be set to 22.7 kg (50 lbs) of fiber /3785 L
(1000 gal) of a 0.24 g/L (20 ppt) linear gel. The rate of the
diluted stream is set to 6700-6800 L/min (42-43 bbl/min) so that
the total rate of diversion slurry (the high-loading stream and the
diluted stream) equals 7950 L/min (50 bbl/min)
[0114] As can be seen in FIG. 3, the diluted stream is pumped at a
rate of 6800 L/min (43 bbl/min), whereas the high-loading stream,
mixed in a batch mixed, is pumped at a rate of 1100 L/min (7
bbl/min) The total pumping rate is 7900 L (50 bbl/min) once the
streams are combined to form the diverting composition or
slurry.
[0115] To mix the high-loading stream with the diluted stream, the
high-loading stream is pumped as fast as possible on a dedicated
pump, or may be supplied to one of the pumps that is otherwise used
for the diluted stream, while maintaining rate of other fracturing
pumps.
[0116] After the mixing of the high-loading stream with the
diluting stream, a cleaning operation including pumping at least
795 L (5 bbl)or at least 1590 L (10nnl) from linear gel to clean
the lines that were used to pump the high-loading stream is
performed. Then, the fiber pumping through the high-loading stream
lines is stopped, and once the last fraction of proppant has passed
the perforations, the injection rate is slowed to 3180 L/min (20
bbl/min) when squeezing particles through the perforations.
[0117] As shown in FIG. 4, the diverting composition or slurry
according to the embodiments described herein allows for an
observed pressure when the diverting composition hits the
perforation ranges to be from 3.1 to 21.4 MPa (450 to 3100 psi). At
stage #10, when the pressure increase reaches an amplitude of 24.1
MPa (3500 psi), the pressure went down sharply and stabilized at a
pressure gain of 15 MPa (2180 psi). This shows that the pressure
increased by 24.1 MPa (3500 psi), when the diverter hit the
perforations. The pressure went down sharply later on, but still
remained very high. Overall, the gain in treatment pressure shows
that perforation clusters were plugged effectively using the
diverting composition.
[0118] In the following examples relating to non-bridging and/or
proppant-carrying fibers, slickwater and low viscosity linear guar
fluids were prepared from tap water. The slickwater contained 1
mL/L (1 gpt) of a concentrated friction reducer solution. Then,
depending on the test, two types of linear guar fluids were
prepared: [0119] In the model static settling test in cylinder used
in example 1, a fluid A was used, it contained linear guar fluid
containing 5.4 g/L (45 ppt) guar and 0.48 kg/L (4ppa) of 12/18 mesh
proppant were used, these proppant was obtained from CARBOPROP.TM.
from Carboceramics (Houston, Tex., USA); [0120] In the settling
test in narrow slot used in example 2, a fluid B was used, it
contained a linear gel containing 2.4 g/L (20 ppt) guar and 0.12 to
0.24 kg/L (2 ppa) of 40/70 mesh proppant were used, these proppant
were BADGER.TM. sand from Badger Mining Corporation (Berlin, Wis.,
USA).
[0121] The fibers used in the following examples were polylactic
acid fibers that were obtained from Trevira GmbH (Germany). Both
mid and low temperature resistant fibers were used, the mid
temperature fibers generally being useful in treatments with a
formation temperature in the range of 94-149.degree. C., and the
low temperature resistant fibers at 60-93.degree. C., of those
tested in these examples. The fibers were straight (uncrimped), or
low crimp (4-5 crimps/cm) or high crimp (>5 crimps/cm, e.g.,
8-15 crimps/cm). In the fibers evaluated in these examples, the low
crimp fibers performed well in terms of bridging resistance and
inhibiting proppant settling at lower fiber loadings. Fibers with
diameters from 8 to 13 microns and lengths from 3 to 12 mm were
evaluated, and of those tested in these examples, the fibers with a
diameter of 8-9.5 microns and a length of 6 mm performed well in
terms of bridging resistance and inhibiting proppant settling at
lower fiber loadings. The characteristics of the fibers used and
other examples of suitable fibers in some embodiments are
identified in Table 1.
TABLE-US-00001 TABLE 1 Fibers used in experimental tests and other
exemplary fibers. Fiber Hydrolysis T Diameter, Length, ID Range
Crimps/cm microns mm NF1 Mid 0 13 6 NF2 Low 0 12 6 CF1 Mid Low 10 4
CF2 Mid Low 10 6 CF3 Mid Low 10 8 CF4 Mid Low 10 12 CF5 Mid Low 12
4 CF6 Mid Low 12 6 CF7 Mid Low 12 8 CF8 Mid Low 12 12 CF9 Low Low
10 4 CF10 Low Low 10 6 CF11 Low Low 10 8 CF12 Low Low 10 12 CF13
Low High 10 4 CF14 Low High 10 6 CF15 Low High 10 8 CF16 Low High
10 12 CF17 Low Low 12 4 CF18 Low Low 12 6 CF19 Low Low 12 8 CF20
Low Low 12 12 CF21 Low High 12 4 CF22 Low High 12 6 CF23 Low High
12 8 CF24 Low High 12 12
[0122] FIGS. 6 to 13 are the results of test obtained with the
proppant settling cylinder test.
[0123] The model proppant settling test involved placing the fluid
in a graduated cylinder and recording the upper level of dispersed
proppant in the fluid. The upper level of dispersed proppant was
recorded at periodic time intervals, e.g., 0, 10, 30, 60, 90 and
120 minutes while maintaining settling conditions. The proppant
settling fraction was calculated as:
Proppant settling = [ initial proppant level ( t = 0 ) ] - [ upper
proppant level at time n ] [ initial proppant level ( t = 0 ) ] - [
final proppant level ( t = .infin. ) ] ##EQU00002##
[0124] Concerning the bridging screen test apparatus used is seen
in FIGS. 5A and 5B. The fluid being tested was pumped through the
apparatus at a flow rate of 10-500 mL/min for a period of at least
1 minute (at the end of the time period the total volume of fluid
pumped was 500 mL). Formation of a fiber plug in the slot (1-2 mm)
was indicated by a pressure rise. Bridging tests using the test
apparatus of FIGS. 5A and 5B were conducted without proppant unless
otherwise noted. The fluid was recorded as negative for bridge
formation if no plug was formed.
[0125] A narrow fracture flow test apparatus was also employed for
more in depth analysis. The narrow fracture flow test apparatus
employed parallel glass panes with a length of 3 m, height of 0.5 m
and width of 2 mm for visualization of the fluid and proppant at a
flow rate up to 50 L/min. The narrow fracture flow tests were run
with L-, T- and X-shape slot orientation.
EXAMPLE 1
[0126] Proppant Settling. In this example, fluid A was used. The
tests were made to compare one fiber with another, and estimate the
behavior of any new fiber as a proppant settling inhibitor. The
tests were made in a linear gel since settling test in a slickwater
type of fluid may not be representative as the settling may occur
immediately.
[0127] A fluid with 0.48 g/L of fibers NF1-NF2 and CF1-CF 24 with
0.48 kg/L (4 ppa) proppant was prepared. The data which are shown
in FIG. 6 indicate the crimped fibers inhibited proppant settling
better than the uncrimped fibers.
[0128] The qualitative results in FIGS. 7 and 8 indicate that the
mid temperature fiber CF2 (10 microns/6 mm) and the low temperature
fiber CF10 (10 microns/6 mm) indicate the fiber loading was reduced
by 25% using the crimped fibers in place of the uncrimped fibers NF
1 and NF2, respectively. The results in FIGS. 9 and 10 indicate
that 10 micron diameter fibers inhibit inhibited proppant settling
to a greater extent than the 12 micron fibers. The results in FIGS.
11 and 12 indicate that 6 mm long fibers provided more or
equivalent proppant settling inhibition relative to 4, 8 and 12 mm
fibers. The results in FIG. 13 show that low crimp fibers provided
better inhibition of proppant settling than high crimp fibers. The
data generally show CF2 and CF10 (10 micron, 6 mm, low crimp) had
the best settling inhibition characteristics.
[0129] Due to the difficulty of applying static proppant settling
test in cylinder to slickwater due to immediate settling,
experiments on proppant settling in narrow slot in static
conditions were not run on this test equipment, however,
experiments with fluid B that has a lower viscosity were run to
confirm the findings evidenced from the cylinder test with linear
gel A. The results are available in FIG. 14 and confirm the
tendencies observed.
EXAMPLE 2
[0130] Fiber Bridging in Low Viscosity Guar Fluid. In this example,
the fluid B was prepared, it contained a linear guar fluid, 2.4 g/L
(20 ppt) guar, at 4.8 g/L (40 ppt) of fibers NF1, CF10 and CF14
without proppant. The bridge screening test results are presented
in Table 2.
TABLE-US-00002 TABLE 2 Screening Bridge Testing. Linear Fiber Fiber
Fiber Flow rate, velocity, NF1 CF10 CF14 mL/min cm/s (uncrimped)
(low crimp) (high crimp) 10 0.57 Bridged Bridged Bridged 50 2.86
Bridged Bridged Bridged 75 4.29 Bridged Bridged Bridged 100 5.72
Bridged Bridged Bridged 150 8.59 Bridged No Bridge Bridged 200 11.4
Bridged No Bridge No Bridge 250 14.3 Bridged No Bridge No Bridge
300 17.2 Bridged No Bridge No Bridge 350 20.0 No Bridge No Bridge
No Bridge
[0131] The foregoing data show that fibers can be used in
fracturing treatments using slickwater and linear gels having a low
viscosity. With the appropriate fiber selection, bottom hole
temperatures of 60-204.degree. C. (140-400.degree. F.) may be
applicable. The fibers provide better proppant transport and
reduced settling with reduced water requirements (higher proppant
loading), reduced proppant requirements (better proppant placement)
and reduced power requirements (lower fluid viscosity and less
pressure drop). The fibers may increase proppant transport in a low
viscosity fluid. The fibers may be degradable after placement in
the formation. The fibers can be used in hybrid treatments such as
heterogeneous proppant placement and/or pulsed proppant and/or
fiber pumping operation modes.
[0132] Although the preceding description has been described herein
with reference to particular means, materials and embodiments, it
is not intended to be limited to the particulars disclosed herein;
rather, it extends to all functionally equivalent structures,
methods and uses, such are within the scope of the appended
claims.
* * * * *