U.S. patent application number 13/854038 was filed with the patent office on 2014-10-02 for stabilized fluids in well treatment.
This patent application is currently assigned to Schlumberger Technology Corporation. The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Yiyan Chen, Hemant K. J. Ladva, Anthony Loiseau, Dmitriy Ivanovich Potapenko.
Application Number | 20140290943 13/854038 |
Document ID | / |
Family ID | 51619681 |
Filed Date | 2014-10-02 |
United States Patent
Application |
20140290943 |
Kind Code |
A1 |
Ladva; Hemant K. J. ; et
al. |
October 2, 2014 |
Stabilized Fluids In Well Treatment
Abstract
Proppant pillar placement in a fracture with a stabilized slurry
treatment fluid. A method of placing a proppant pack by injecting a
well treatment fluid comprising proppant and a stabilized slurry,
and a slurry destabilizing system to consolidate solids from the
slurry, and placing the proppant in the fracture in a plurality of
proppant clusters forming pillars spaced apart by fluid flow
channels from the formation through the fracture toward the
wellbore. Also, a system for implementing the method, and the
propped fracture system obtained as a result of placing the
proppant pack into the fracture according to the method.
Inventors: |
Ladva; Hemant K. J.;
(Missouri City, TX) ; Potapenko; Dmitriy Ivanovich;
(Sugar Land, TX) ; Loiseau; Anthony; (Sugar Land,
TX) ; Chen; Yiyan; (Sugar Land, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Assignee: |
Schlumberger Technology
Corporation
Sugar Land
TX
|
Family ID: |
51619681 |
Appl. No.: |
13/854038 |
Filed: |
March 29, 2013 |
Current U.S.
Class: |
166/280.1 ;
166/69 |
Current CPC
Class: |
E21B 43/267
20130101 |
Class at
Publication: |
166/280.1 ;
166/69 |
International
Class: |
E21B 43/267 20060101
E21B043/267 |
Claims
1. A method of placing a proppant pack into a fracture formed in a
subterranean formation, the method comprising: injecting a well
treatment fluid through a wellbore into a fracture in a
subterranean formation, wherein at least a portion of the well
treatment fluid comprises a proppant-containing stage, wherein at
least a portion of the well treatment fluid comprises a stabilized
slurry stage and wherein the proppant-containing and stabilized
slurry portions may be the same or different; injecting a
destabilizing system into the fracture with the well treatment
fluid to destabilize the slurry stage and form regions of
consolidated proppant from the destabilized slurry stage; and
placing a plurality of proppant clusters forming pillars from the
consolidated proppant regions spaced apart by fluid flow channels
from the formation through the fracture toward the wellbore.
2. The method of claim 1 wherein the stabilized slurry comprises a
liquid phase, and wherein the slurry destabilizing system comprises
a liquid-removing agent to remove fluid from the slurry.
3. The method of claim 2 wherein the liquid phase comprises water
and the liquid-removal agent comprises a hydratable compound.
4. The method of claim 2 wherein the liquid phase comprises water
and the liquid-removal agent comprises a superabsorbent
polymer.
5. The method of claim 1, further comprising: sequentially
injecting a first stage of the treatment fluid into the formation
followed by a second stage of the treatment fluid, wherein the
first and second stages have different viscosities, different
specific gravities, or both, to initiate viscous fingering; wherein
the stabilized slurry comprises the proppant in the first stage;
wherein the destabilizing system comprises a crosslinkable material
in the first stage, and a crosslinking agent in at least one of the
first and second stages to crosslink the crosslinkable material in
the pillars.
6. The method of claim 5 wherein the specific gravity of the first
stage is matched with the specific gravity of the second stage to
mitigate gravity effects.
7. The method of claim 5 wherein the crosslinkable material
comprises a polysaccharide, and wherein the crosslinking agent
comprises a source of borate or a polyvalent metal.
8. The method of claim 7 wherein one of the first and second stages
comprises a pH control material to provide an alkaline pH and the
other one of the first and second stages comprises the source of
borate or polyvalent metal.
9. The method of claim 8 wherein the first stage comprises
subproppant particles and has a slurry solids volume fraction (SVF)
of 0.4 or more; and wherein the second stage is free of solids or
has an SVF less than 0.4.
10. The method of claim 1, further comprising: alternatingly
injecting a plurality of pulsed first and second slugs of the well
treatment fluid, wherein the first and second slugs each comprise a
said stabilized slurry which may be the same or different; wherein
the slurry destabilizing system comprises a reagent selectively
present in one of the first and second slugs to respectively form
the pillars from consolidated proppant packs and the channels from
relatively permeable proppant packs.
11. The method of claim 10 wherein the first and second slugs
comprise a crosslinkable material and wherein the reagent comprises
a solid particulated crosslinking agent.
12. The method of claim 10 wherein water and the reagent comprises
a hydratable compound to remove water from at least one of the
slurries.
13. The method of claim 10 wherein the stabilized slurries comprise
water and the reagent comprises a superabsorbent polymer to remove
water from at least one of the slurries.
14. The method of claim 1, wherein the stabilized slurry is formed
by at least one of: (1) introducing sufficient particles into the
slurry to increase the solids volume fraction (SVF) of the slurry
fluid to at least 0.4; (2) increasing a low-shear viscosity of the
slurry to at least 1 Pa-s (5.11 s.sup.-1, 25.degree. C.); (3)
increasing a yield stress of the slurry to at least 1 Pa; (4)
increasing apparent viscosity of the slurry to at least 50 mPa-s
(170 s.sup.-1, 25.degree. C.); (5) introducing a multimodal solids
phase into the slurry; (6) introducing a solids phase having a
packed volume fraction (PVF) greater than 0.7 into the slurry; (7)
introducing into the slurry a viscosifier selected from
viscoelastic surfactants and hydratable gelling agents; (8)
introducing colloidal particles into the slurry; (9) reducing a
particle-fluid density delta in the slurry to less than 1.6 g/mL;
(10) introducing particles into the slurry having an aspect ratio
of at least 6; (11) introducing ciliated or coated proppant into
the slurry; and (12) combinations thereof.
15. A propped fracture system obtained as a result of placing a
proppant pack into a fracture according to a method comprising:
injecting a well treatment fluid through a wellbore into a fracture
in a subterranean formation, wherein at least a portion of the well
treatment fluid comprises a proppant-containing stage, wherein at
least a portion of the well treatment fluid comprises a stabilized
slurry stage and wherein the proppant-containing and stabilized
slurry portions may be the same or different; injecting a
destabilizing system into the fracture with the well treatment
fluid to destabilize the slurry stage and form regions of
consolidated proppant from the destabilized slurry stage; and
placing a plurality of proppant clusters forming pillars from the
consolidated proppant regions spaced apart by fluid flow channels
from the formation through the fracture toward the wellbore.
16. A system for fracturing a subterranean formation, comprising: a
supply module to inject a well treatment fluid through a wellbore
into a fracture in a subterranean formation, wherein at least a
portion of the well treatment fluid comprises a proppant-containing
stage fluid, wherein at least a portion of the well treatment fluid
comprises a stabilized slurry stage fluid and wherein the
proppant-containing and stabilized slurry portions may be the same
or different fluids; and a destabilizing system in communication
with the supply module for injection into the fracture with the
well treatment fluid to destabilize the slurry stage fluid, form
regions of consolidated proppant from the destabilized slurry stage
fluid and form pillars spaced apart by fluid flow channels from the
formation through the fracture toward the wellbore.
17. The system of claim 16 wherein the stabilized slurry comprises
a liquid phase, and wherein the slurry destabilizing system
comprises a liquid-removing agent to remove fluid from the
stabilized slurry.
18. The system of claim 16, further comprising: a pump system to
sequentially inject a first stage of the treatment fluid into the
formation followed by a second stage of the treatment fluid,
wherein the first stage treatment fluid has a higher viscosity
relative to the second stage treatment fluid, or wherein the first
and second stages have different specific gravities, to initiate
viscous fingering; wherein the stabilized slurry comprises the
proppant in the first stage fluid; wherein the destabilizing system
comprises a crosslinkable material in the first stage fluid, and a
crosslinking agent in at least one of the first and second stage
fluids to crosslink the crosslinkable material in the pillars.
19. The system of claim 18 wherein the crosslinkable material
comprises a polysaccharide, and wherein the crosslinking agent
comprises a source of borate or a polyvalent metal.
20. The system of claim 19 wherein one of the first and second
stage fluids comprises a pH control material to provide an alkaline
pH and the other one of the first and second stage fluids comprises
the source of borate or polyvalent metal.
21. The system of claim 20 wherein the stabilized slurry comprises
the proppant and subproppant particles, has a solids volume
fraction (SVF) of 0.6 or more and solids comprising a packed volume
fraction (PVF) of 0.7 or more; and wherein the second stage fluid
is free of solids or has an SVF less than 0.05.
22. The system of claim 16, further comprising: a pump system to
alternatingly inject a plurality of pulsed first and second slugs
of the treatment fluid, wherein the first and second slugs each
comprise a said stabilized slurry; wherein the slurry destabilizing
system comprises a primary reagent selectively present in one of
the first and second slugs to respectively form the pillars from
consolidated proppant packs and the channels from relatively
permeable proppant packs.
23. The system of claim 22 wherein the first and second slugs
comprise a crosslinkable material and wherein the reagent comprises
a solid particulated crosslinking agent.
24. The system of claim 23 wherein the stabilized slurries comprise
a liquid phase, and wherein the reagent comprises a solid
liquid-removal agent to remove fluid from the stabilized
slurry.
25. The system of claim 16, wherein the stabilized slurry comprises
at least one of the stability indicia selected from: (1) a solids
volume fraction (SVF) of at least 0.4; (2) a low-shear viscosity of
at least 1 Pa-s (5.11 s.sup.-1, 25.degree. C.); (3) a yield stress
of at least 1 Pa; (4) an apparent viscosity of at least 50 mPa-s
(170 s.sup.-1, 25.degree. C.); (5) a multimodal solids phase; (6) a
solids phase having a packed volume fraction (PVF) greater than
0.7; (7) a viscosifier selected from viscoelastic surfactants, in
an amount ranging from 0.01 up to 7.2 g/L (60 ppt), and hydratable
gelling agents in an amount ranging from 0.01 up to 4.8 g/L (40
ppt) based, on the volume of fluid phase; (8) colloidal particles;
(9) a particle-fluid density delta less than 1.6 g/mL; (10)
particles having an aspect ratio of at least 6; (11) ciliated or
coated proppant; and (12) combinations thereof.
Description
RELATED APPLICATION DATA
[0001] None.
BACKGROUND
[0002] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0003] This application relates to stimulation of wells penetrating
subterranean formations, and more specifically to fracture
stimulation by injection of proppant into a fracture to form
regions of low resistance to flow through the fracture for the
production of hydrocarbons.
[0004] Various methods are known for fracturing a subterranean
formation to enhance the production of fluids therefrom. In the
typical application, a pressurized fracturing fluid hydraulically
creates and propagates a fracture. The fracturing fluid carries
proppant particulates into the extending fracture. When the
fracturing fluid is removed, the fracture does not completely close
from the loss of hydraulic pressure; instead, the fracture remains
propped open by the packed proppant, allowing fluids to flow from
the formation through the proppant pack to the production
wellbore.
[0005] The success of the fracturing treatment may depend on the
ability of fluids to flow from the formation through the proppant
pack. The prior art has sought to increase the permeability of the
proppant pack by increasing the porosity of the interstitial
channels between adjacent proppant particles within a homogenous
proppant matrix, as in, for example, U.S. Pat. No. 7,255,169, U.S.
Pat. No. 7,281,580 and U.S. Pat. No. 7,571,767, incorporated herein
by reference.
[0006] Another approach to improving fracture conductivity has been
to try heterogeneous proppant placement techniques to construct
proppant clusters, as opposed to constructing a continuous proppant
pack. U.S. Pat. No. 6,776,235 incorporated herein by reference
discloses a method for fracturing a subterranean formation
involving alternating stages of proppant containing fracturing
fluids contrasting in their proppant-settling rates to form
proppant clusters as posts that prevent fracture closing, e.g.,
alternating the stages of proppant-laden and proppant-free
fracturing fluids to create proppant clusters, or islands, in the
fracture and channels between them for formation fluids to flow.
The amount of proppant deposited in the fracture during each stage
is modulated by varying the fluid transport characteristics, such
as viscosity and elasticity, the proppant densities, diameters, and
concentrations and the fracturing fluid injection rate; however,
the positioning of the proppant-containing fluid can be difficult
to control.
[0007] Other heterogeneous proppant placement techniques are
disclosed in, for example, U.S. Pat. No. 4,029,149; U.S. Pat. No.
6,860,328; U.S. Pat. No. 7,213,651; U.S. Pat. No. 7,581,590; U.S.
Pat. No. 8,082,994; and U.S. Pat. No. 8,205,675; each of which is
hereby incorporated herein by reference. Commonly assigned U.S.
Pat. No. 7,923,415, US 2011/0198089, US 2012/0247764, US
2012/0305254 and US 2012/0305247 are hereby incorporated herein by
reference.
[0008] Improvements in well treatment slurries and slurry
treatments, systems, equipment, methods, and the like in general
and for propping a fracture in particular, are desired.
SUMMARY
[0009] In some embodiments herein, stabilized treatment slurries,
proppants and destabilizing systems are used in methods or systems
to place consolidated proppant pillars in a fracture spaced apart
by fluid flow channels, which may be open channels or relatively
permeable channels filled with permeable proppant packs relative to
the pillars, for the flow of reservoir fluid(s) from the formation
through the fracture toward the wellbore.
[0010] According to some embodiments, methods of placing proppant
packs into a fracture formed in a subterranean formation comprises:
injecting well treatment fluids, at least a portion of the well
treatment fluids comprises a proppant-containing stage, at least a
portion of the well treatment fluids comprises a stabilized slurry
stage and the proppant-containing and stabilized slurry portions
may be the same or different; injecting a destabilizing system to
destabilize the slurry and form regions of consolidated proppant
from the destabilized slurry stage; and placing a plurality of
clusters forming pillars from the consolidated proppant regions
spaced apart by fluid flow channels from the formation through the
fracture toward the wellbore.
[0011] According to some embodiments, a propped fracture system is
obtained as a result of placing the proppant pack into the fracture
according to the methods described herein.
[0012] According to some embodiments, a system for fracturing a
subterranean formation comprises a supply module to inject a well
treatment fluid which comprises proppants and stabilized treatment
slurries through a wellbore into a fracture in a subterranean
formation, and a destabilizing system in communication with the
supply module for injection into the fracture with the well
treatment fluid to form regions of consolidated proppant from the
destabilized slurry stage fluid and form pillars spaced apart by
fluid flow channels from the formation through the fracture toward
the wellbore.
[0013] In some embodiments herein, the treatments, treatment
fluids, systems, equipment, methods, and the like employ a
stabilized treatment slurry (STS) having a solid phase, which may
include proppant, is at least temporarily inhibited from
gravitational settling in the fluid phase. In some embodiments, the
STS may have an at least temporarily controlled rheology, such as,
for example, viscosity, leakoff or yield strength, or other
physical property, such as, for example, specific gravity, solids
volume fraction (SVF), or the like. In some embodiments, the solids
phase of the STS may have an at least temporarily controlled
property, such as, for example, particle size distribution
(including modality(ies)), packed volume fraction (PVF),
density(ies), aspect ratio(s), sphericity(ies), roundness(es) (or
angularity(ies)), strength(s), permeability(ies), solubility(ies),
reactivity(ies), etc.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] These and other features and advantages will be better
understood by reference to the following detailed description when
considered in conjunction with the accompanying drawings.
[0015] FIG. 1 shows a schematic slurry state progression chart for
a treatment fluid according to some embodiments of the current
application.
[0016] FIG. 2 illustrates fluid stability regions for a treatment
fluid according to some embodiments of the current application.
[0017] FIG. 3 shows the leakoff property of a low viscosity,
stabilized treatment slurry (STS) (lower line) according to some
embodiments of the current application compared to a conventional
crosslinked fluid (upper line).
[0018] FIG. 4 shows a schematic representation of the wellsite
equipment configuration with onsite mixing of an STS according to
some embodiments of the current application.
[0019] FIG. 5 shows a schematic representation of the wellsite
equipment configuration with a pump-ready STS according to some
embodiments of the current application.
[0020] FIG. 6 schematically illustrates in section placement of
stabilized proppant slurry and slurry destabilizer in a hydraulic
fracture operation according to embodiments disclosed.
[0021] FIG. 7 schematically illustrates in section the arrangement
of the wellbore, perforations and the proppant pillars in the
fracture following slurry destabilization in the fracture of FIG.
1.
[0022] FIG. 8 schematically illustrates a side sectional view of a
fracture filled with segregated, consolidated proppant and
permeable proppant regions according to embodiments disclosed.
[0023] FIG. 9 schematically illustrates a side sectional view of a
fracture filled with segregated, consolidated proppant and
proppant-free regions according to embodiments disclosed.
[0024] FIG. 10 schematically illustrates a plan view of a portion
of a fracture filled with peripherally-consolidated proppant
pillars and proppant-free channels according to embodiments
disclosed.
[0025] FIG. 11 schematically illustrates an alternatingly pulsed
proppant/slurry/slurry crosslinker fracture treatment system
according to embodiments disclosed.
[0026] FIG. 12 schematically illustrates a plan view of a portion
of a fracture filled with a proppant/stabilized slurry and a liquid
removal agent.
DETAILED DESCRIPTION OF SOME ILLUSTRATIVE EMBODIMENTS
[0027] For the purposes of promoting an understanding of the
principles of the disclosure, reference will now be made to some
illustrative embodiments of the current application. Like reference
numerals used herein refer to like parts in the various drawings.
Reference numerals without suffixed letters refer to the part(s) in
general; reference numerals with suffixed letters refer to a
specific one of the parts.
[0028] As used herein, "embodiments" refers to non-limiting
examples of the application disclosed herein, whether claimed or
not, which may be employed or present alone or in any combination
or permutation with one or more other embodiments. Each embodiment
disclosed herein should be regarded both as an added feature to be
used with one or more other embodiments, as well as an alternative
to be used separately or in lieu of one or more other embodiments.
It should be understood that no limitation of the scope of the
claimed subject matter is thereby intended, any alterations and
further modifications in the illustrated embodiments, and any
further applications of the principles of the application as
illustrated therein as would normally occur to one skilled in the
art to which the disclosure relates are contemplated herein.
[0029] Moreover, the schematic illustrations and descriptions
provided herein are understood to be examples only, and components
and operations may be combined or divided, and added or removed, as
well as re-ordered in whole or part, unless stated explicitly to
the contrary herein. Certain operations illustrated may be
implemented by a computer executing a computer program product on a
computer readable medium, where the computer program product
comprises instructions causing the computer to execute one or more
of the operations, or to issue commands to other devices to execute
one or more of the operations.
[0030] In embodiments, a method of placing a proppant pack into a
fracture formed in a subterranean formation comprises: injecting a
well treatment fluid through a wellbore into a fracture in a
subterranean formation, wherein at least a portion of the well
treatment fluid comprises a proppant-containing stage, wherein at
least a portion of the well treatment fluid comprises a stabilized
slurry stage and wherein the proppant-containing and stabilized
slurry portions may be the same or different; injecting a
destabilizing system into the fracture with the well treatment
fluid to destabilize the stabilized slurry stage and form regions
of consolidated proppant from the destabilized slurry stage; and
placing a plurality of proppant clusters forming pillars from the
consolidated proppant regions spaced apart by fluid flow channels
from the formation through the fracture toward the wellbore.
[0031] In embodiments, the stabilized slurry may comprise a liquid
phase, and the slurry destabilizing system may comprise a
liquid-removing agent to remove fluid from the slurry, thereby
forming regions of increased solids volume fraction (SVF). In
embodiments, the liquid phase may comprise water, which may
optionally be in a continuous or dispersed aqueous phase in an
emulsion with a hydrophobic phase, and additionally or
alternatively, the liquid-removal agent may comprise a hydratable
compound, a superabsorbent polymer or the like.
[0032] In embodiments, the method may further comprise sequentially
injecting a first stage of the treatment fluid into the formation
followed by a second stage of the treatment fluid, e.g., as an
overflush, wherein the first and second stages have stage a
different viscosities, or wherein the first and second stages have
different specific gravities, or both, wherein the stabilized
slurry comprises the proppant in the first stage, and wherein the
destabilizing system comprises a crosslinkable material in the
first stage, and a crosslinking agent in at least one of the first
and second stages to crosslink the crosslinkable material in the
pillars. In some embodiments, the first stage has a higher
viscosity relative to the second stage to initiate viscous
fingering. In additional or alternate embodiments, the second stage
may have a density matching that of the first stage to mitigate any
gravity effects; or may have a density different from the first
stage to facilitate gravity-mediated fingering. A "matching"
density or specific gravity as used herein is one where the
difference in specific gravity or density between two fluids is
less than 1 g/mL, and in some embodiments the density differences
may be less than 0.9 g/mL, or less than 0.8 g/L, or less than 0.7
g/L, or less than 0.6 g/L, or less than 0.5 g/L, or less than 0.4
g/L, or less than 0.3 g/L, or less than 0.2 g/L, or less than 0.1
g/L, or less than 0.05 g/L.
[0033] In embodiments, the crosslinkable material may be or include
a polysaccharide, and the crosslinking agent may be or include a
source of borate or a polyvalent metal. In embodiments, one of the
first and second stages comprises a pH control material to provide
an alkaline pH and the other one of the first and second stages
comprises the source of borate or polyvalent metal. In embodiments,
the first stage may comprise the polysaccharide and the pH control
agent and the second stage may comprise the source of borate or
polyvalent metal. In embodiments, the first stage may comprise the
polysaccharide and the source of borate or polyvalent metal and the
second stage may comprise the pH control agent. In embodiments, the
first stage may comprise subproppant particles, have an SVF of 0.4
or more, 0.5 or more, 0.6 or more, e.g., 0.56-0.61, and comprise
solids comprising a packed volume fraction (PVF) of 0.7 or more,
and the second stage may be free of solids or have an SVF less than
0.5, or less than 0.4, or less than 0.3, or less than 0.2, or less
than 0.1 or less than 0.05.
[0034] In embodiments, the method may comprise alternatingly
injecting a plurality of pulsed first and second slugs of the well
treatment fluid, wherein the first and second slugs each comprise a
said stabilized slurry which may be the same or different, and
wherein the slurry destabilizing system comprises a reagent
selectively present in one of the first and second slugs to
respectively form the pillars from consolidated proppant packs and
the channels from relatively permeable proppant packs. In
embodiments, the first and second slugs may comprise a
crosslinkable material and the reagent may be or include a solid
particulated crosslinking agent. In embodiments, as mentioned
above, the stabilized slurries may comprise a liquid phase, the
reagent may be or include a solid liquid-removal agent to remove
fluid from at least one of the slurries, the liquid phase may
comprise water, which may optionally be in a continuous or
dispersed aqueous phase in an emulsion with a hydrophobic phase,
and the reagent may be or include a hydratable material,
superabsorbent polymer or the like.
[0035] In embodiments, the method may comprise stabilizing the well
treatment fluid to form the stabilized slurry, wherein the
stabilized slurry meets at least one of the following conditions:
[0036] (1) the slurry has a low-shear viscosity of at least 1 Pa-s
(5.11 s.sup.-1, 25.degree. C.); or [0037] (2) the slurry has a
Herschel-Buckley (including Bingham plastic) yield stress (as
determined in the manner described below) equal to or greater than
1 Pa; or [0038] (3) the largest particle mode in the slurry has a
static settling rate less than 0.01 mm/hr; or [0039] (4) the depth
of any free fluid at the end of a 72-hour static settling test
condition or an 8 h @15 Hz/10 d-static dynamic settling test
condition (4 hours vibration followed by 20 hours static followed
by 4 hours vibration followed finally by 10 days of static
conditions) is no more than 2% of total depth; or [0040] (5) the
apparent dynamic viscosity (25.degree. C., 170 s.sup.-1) across
column strata after the 72-hour static settling test condition or
the 8 h @15 Hz/10 d-static dynamic settling test condition is no
more than +/-20% of the initial dynamic viscosity; or [0041] (6)
the slurry solids volume fraction (SVF) across the column strata
below any free water layer after the 72-hour static settling test
condition or the 8 h @15 Hz/10 d-static dynamic settling test
condition is no more than 5% greater than the initial SVF; or
[0042] (7) the density across the column strata below any free
water layer after the 72-hour static settling test condition or the
8 h@15 Hz/10 d-static dynamic settling test condition is no more
than 1% of the initial density.
[0043] In some embodiments, the slurry has a low-shear viscosity of
at least 1 Pa-s (5.11 s.sup.-1, 25.degree. C.).
[0044] In some embodiments, the depth of any free fluid at the end
of the 8 h@15 Hz/10 d-static dynamic settling test condition is no
more than 2% of total depth, the apparent dynamic viscosity
(25.degree. C., 170 s.sup.-1) across column strata after the 8 h@15
Hz/10 d-static dynamic settling test condition is no more than
+/-20% of the initial dynamic viscosity, the slurry solids volume
fraction (SVF) across the column strata below any free water layer
after the 8 h@15 Hz/10 d-static dynamic settling test condition is
no more than +/-5% of the initial SVF, and the density across the
column strata below any free water layer after the 8 h @15 Hz/10
d-static dynamic settling test condition is no more than 1% of the
initial density.
[0045] In embodiments, the stabilized slurry is formed by at least
one of the following slurry stabilization operations: (1)
introducing sufficient particles into the slurry or treatment fluid
to increase the SVF of the treatment fluid to at least 0.4; (2)
increasing a low-shear viscosity of the slurry or treatment fluid
to at least 1 Pa-s (5.11 s.sup.-1, 25.degree. C.); (3) increasing a
yield stress of the slurry or treatment fluid to at least 1 Pa; (4)
increasing apparent viscosity of the slurry or treatment fluid to
at least 50 mPa-s (170 s.sup.-1, 25.degree. C.); (5) introducing a
multimodal solids phase into the slurry or treatment fluid; (6)
introducing a solids phase having a PVF greater than 0.7 into the
slurry or treatment fluid; (7) introducing into the slurry or
treatment fluid a viscosifier selected from viscoelastic
surfactants, e.g., in an amount ranging from 0.01 up to 7.2 g/L (60
ppt), and hydratable gelling agents, e.g., in an amount ranging
from 0.01 up to 4.8 g/L (40 ppt) based on the volume of fluid
phase; (8) introducing colloidal particles into the slurry or
treatment fluid; (9) reducing a particle-fluid density delta to
less than 1.6 g/mL (e.g., introducing particles having a specific
gravity less than 2.65 g/mL, carrier fluid having a density greater
than 1.05 g/mL or a combination thereof); (10) introducing
particles into the slurry or treatment fluid having an aspect ratio
of at least 6; (11) introducing ciliated or coated proppant into
slurry or treatment fluid; and (12) combinations thereof. The
techniques to stabilize particle settling in various embodiments
herein may use any one, or a combination of any two or three, or
all of these approaches, i.e., a manipulation of particle/fluid
density, carrier fluid viscosity, solids fraction, yield stress,
and/or may use another approach. The slurry stabilization
operations may be separate or concurrent, e.g., introducing a
single viscosifier may also increase low-shear viscosity, yield
stress, apparent viscosity, etc., or alternatively or additionally
with respect to a viscosifier, separate agents may be added to
increase low-shear viscosity, yield stress and/or apparent
viscosity.
[0046] In embodiments, the stabilized slurry is formed by at least
two of the slurry stabilization operations, such as, for example,
increasing the SVF and increasing the low-shear viscosity of the
treatment fluid, and optionally one or more of increasing the yield
stress, increasing the apparent viscosity, introducing the
multimodal solids phase, introducing the solids phase having the
PVF greater than 0.7, introducing the viscosifier, introducing the
colloidal particles, reducing the particle-fluid density delta,
introducing the particles having the aspect ratio of at least 6,
introducing the ciliated or coated proppant or a combination
thereof.
[0047] In embodiments, the stabilized slurry is formed by at least
three of the slurry stabilization operations, such as, for example,
increasing the SVF, increasing the low-shear viscosity and
introducing the multimodal solids phase, and optionally one or more
of increasing the yield stress, increasing the apparent viscosity,
introducing the solids phase having the PVF greater than 0.7,
introducing the viscosifier, introducing the colloidal particles,
reducing the particle-fluid density delta, introducing the
particles having the aspect ratio of at least 6, introducing the
ciliated or coated proppant or a combination thereof.
[0048] In embodiments, the stabilized slurry is formed by at least
four of the slurry stabilization operations, such as, for example,
increasing the SVF, increasing the low-shear viscosity, increasing
the yield stress and increasing apparent viscosity, and optionally
one or more of introducing the multimodal solids phase, introducing
the solids phase having the PVF greater than 0.7, introducing the
viscosifier, introducing colloidal particles, reducing the
particle-fluid density delta, introducing particles into the
treatment fluid having the aspect ratio of at least 6, introducing
the ciliated or coated proppant or a combination thereof.
[0049] In embodiments, the stabilized slurry is formed by at least
five of the slurry stabilization operations, such as, for example,
increasing the SVF, increasing the low-shear viscosity, increasing
the yield stress, increasing the apparent viscosity and introducing
the multimodal solids phase, and optionally one or more of
introducing the solids phase having the PVF greater than 0.7,
introducing the viscosifier, introducing colloidal particles,
reducing the particle-fluid density delta, introducing particles
into the treatment fluid having the aspect ratio of at least 6,
introducing the ciliated or coated proppant or a combination
thereof.
[0050] In embodiments, the stabilized slurry comprises solids
comprising 60-75 volume percent proppant larger than 100 mesh, 5-20
volume percent 100 mesh sand, 5-20 volume percent silica flour, and
8-30 volume percent of 1-10 micron particles, based on the total
volume of solids in the stabilized slurry (BVOB), and from 1.2 to
4.8 g/L (10-40 ppt) of a hydratable gelling agent.
[0051] In embodiments, a propped fracture system may be obtained as
a result of placing the proppant pack into the fracture according
to the methods described herein.
[0052] In embodiments, a system for fracturing a subterranean
formation may comprise: a supply module to inject the well
treatment fluid through the wellbore into the fracture in the
subterranean formation, wherein at least a portion of the well
treatment fluid comprises the proppant-containing stage fluid,
wherein at least a portion of the well treatment fluid comprises
the stabilized slurry stage fluid and wherein the
proppant-containing and stabilized slurry portions may be the same
or different fluids; and a destabilizing system in communication
with the supply module for injection into the fracture with the
well treatment fluid to destabilize the slurry stage fluid, form
regions of consolidated proppant from the destabilized slurry stage
fluid and form pillars spaced apart by fluid flow channels, which
may be open or permeable, from the formation through the fracture
toward the wellbore.
[0053] In embodiments, the system may comprise a pump system to
sequentially inject the first stage of the treatment fluid into the
formation followed by the second stage of the treatment fluid,
wherein the first stage treatment fluid has a higher viscosity
relative to the second stage treatment fluid to initiate viscous
fingering, wherein the stabilized slurry comprises the proppant in
the first stage fluid, and wherein the destabilizing system
comprises the crosslinkable material in the first stage fluid, and
the crosslinking agent in at least one of the first and second
stage fluids to crosslink the crosslinkable material in the
pillars. As mentioned above, the crosslinkable material may be or
include a polysaccharide, and the crosslinking agent may be or
include a source of borate or a polyvalent metal; one of the first
and second stages may comprise a pH control material to provide an
alkaline pH and the other one of the first and second stages may
comprise the source of borate or polyvalent metal; the first stage
may comprise the polysaccharide and the pH control agent and the
second stage may comprise the source of borate or polyvalent metal;
the first stage may comprise the polysaccharide and the source of
borate or polyvalent metal and the second stage may comprise the pH
control agent; and/or the first stage may comprise subproppant
particles, have an SVF of 0.4 or more, 0.5 or more, or 0.6 or more
and comprise solids comprising a packed volume fraction (PVF) of
0.7 or more, and the second stage may be free of solids or have an
SVF less than 0.5, or less than 0.4, or less than 0.3, or less than
0.2, or less than 0.1 or less than 0.05.
[0054] In embodiments, the system may comprise a pump system, such
as, for example, tanks, pumps and/or valves as appropriate, to
alternatingly inject a plurality of pulsed first and second slugs
of the treatment fluid, wherein the first and second slugs each
comprise a said stabilized slurry, wherein the slurry destabilizing
system comprises a reagent selectively present in one of the first
and second slugs to respectively form the pillars from consolidated
proppant packs and the channels from relatively permeable proppant
packs. In embodiments, the first and second slugs comprise a
crosslinkable material and wherein the reagent comprises a solid
particulated crosslinking agent. As mentioned above, the
crosslinkable material may be or include a polysaccharide, and the
crosslinking agent may be or include a source of borate or a
polyvalent metal; one of the first and second stages may comprise a
pH control material to provide an alkaline pH and the other one of
the first and second stages may comprise the source of borate or
polyvalent metal; the first stage may comprise the polysaccharide
and the pH control agent and the second stage may comprise the
source of borate or polyvalent metal; the first stage may comprise
the polysaccharide and the source of borate or polyvalent metal and
the second stage may comprise the pH control agent; and/or the
first stage may comprise subproppant particles, have an SVF of 0.3
or more, or 0.4 or more, or 0.5 or more, or 0.6 or more up to an
upper limit of SVF=PVF, or up to any higher upper limit of 0.9,
0.85, 0.8, or 0.75, or 0.7, or 0.65, or 0.6, and comprise solids
comprising a packed volume fraction (PVF) of 0.5 or more, e.g., 0.5
to 0.9, or 0.6 or more, or 0.7 or more, 0.75 or more, or 0.8 or
more; and the second stage may be free of solids or have an SVF
less than that of the first stage, e.g., less than 0.6, or less
than 0.5, or less than 0.4, or less than 0.3, or less than 0.2, or
less than 0.1 or less than 0.05.
[0055] In embodiments as mentioned above, the stabilized slurry in
the system may meet at least one of the conditions listed above. In
some embodiments of the system, the stabilized slurry comprises at
least one of the following stability indicia: (1) an SVF of at
least 0.4 up to SVF=PVF; (2) a low-shear viscosity of at least 1
Pa-s (5.11 s.sup.-1, 25.degree. C.); (3) a yield stress (as
determined herein) of at least 1 Pa; (4) an apparent viscosity of
at least 50 mPa-s (170 s.sup.-1, 25.degree. C.); (5) a multimodal
solids phase; (6) a solids phase having a PVF greater than 0.7; (7)
a viscosifier selected from viscoelastic surfactants, in an amount
ranging from 0.01 up to 7.2 g/L (60 ppt), and hydratable gelling
agents in an amount ranging from 0.01 up to 4.8 g/L (40 ppt) based
on the volume of fluid phase; (8) colloidal particles; (9) a
particle-fluid density delta less than 1.6 g/mL, (e.g., particles
having a specific gravity less than 2.65 g/mL, carrier fluid having
a density greater than 1.05 g/mL or a combination thereof); (10)
particles having an aspect ratio of at least 6; (11) ciliated or
coated proppant; and (12) combinations thereof.
[0056] In some embodiments, the stabilized slurry comprises at
least two of the stability indicia, such as for example, the SVF of
at least 0.4 and the low-shear viscosity of at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.); and optionally one or more of the yield
stress of at least 1 Pa, the apparent viscosity of at least 50
mPa-s (170 s.sup.-1, 25.degree. C.), the multimodal solids phase,
the solids phase having a PVF greater than 0.7, the viscosifier,
the colloidal particles, the particle-fluid density delta less than
1.6 g/mL, the particles having an aspect ratio of at least 6, the
ciliated or coated proppant, or a combination thereof.
[0057] In some embodiments, the stabilized slurry comprises at
least three of the stability indicia, such as for example, the SVF
of at least 0.4, the low-shear viscosity of at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.) and the yield stress of at least 1 Pa; and
optionally one or more of the apparent viscosity of at least 50
mPa-s (170 s.sup.-1, 25.degree. C.), the multimodal solids phase,
the solids phase having a PVF greater than 0.7, the viscosifier,
the colloidal particles, the particle-fluid density delta less than
1.6 g/mL, the particles having an aspect ratio of at least 6, the
ciliated or coated proppant, or a combination thereof.
[0058] In some embodiments, the stabilized slurry comprises at
least four of the stability indicia, such as for example, the SVF
of at least 0.4, the low-shear viscosity of at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.), the yield stress of at least 1 Pa and the
apparent viscosity of at least 50 mPa-s (170 s.sup.-1, 25.degree.
C.); and optionally one or more of the multimodal solids phase, the
solids phase having a PVF greater than 0.7, the viscosifier,
colloidal particles, the particle-fluid density delta less than 1.6
g/mL, the particles having an aspect ratio of at least 6, the
ciliated or coated proppant, or a combination thereof.
[0059] In some embodiments, the stabilized slurry comprises at
least five of the stability indicia, such as for example, the SVF
of at least 0.4, the low-shear viscosity of at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.), the yield stress of at least 1 Pa, the
apparent viscosity of at least 50 mPa-s (170 s.sup.-1, 25.degree.
C.) and the multimodal solids phase, and optionally one or more of
the solids phase having a PVF greater than 0.7, the viscosifier,
colloidal particles, the particle-fluid density delta less than 1.6
g/mL, the particles having an aspect ratio of at least 6, the
ciliated or coated proppant, or a combination thereof.
[0060] In some embodiments, the stabilized slurry comprises at
least six of the stability indicia, such as for example, the SVF of
at least 0.4, the low-shear viscosity of at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.), the yield stress of at least 1 Pa, the
apparent viscosity of at least 50 mPa-s (170 s.sup.-1, 25.degree.
C.), the multimodal solids phase and the solids phase having a PVF
greater than 0.7, and optionally one or more of the viscosifier,
colloidal particles, the particle-fluid density delta less than 1.6
g/mL, the particles having an aspect ratio of at least 6, the
ciliated or coated proppant, or a combination thereof.
[0061] As used herein, the terms "treatment fluid" or "wellbore
treatment fluid" are inclusive of "fracturing fluid" or "treatment
slurry" and should be understood broadly. These may be or include a
liquid, a solid, a gas, and combinations thereof, as will be
appreciated by those skilled in the art. A treatment fluid may take
the form of a solution, an emulsion, slurry, or any other form as
will be appreciated by those skilled in the art. It should be
understood that, although a substantial portion of the following
detailed description may be provided in the context of oilfield
hydraulic fracturing operations, other oilfield operations such as
cementing, gravel packing, etc., or even non-oilfield well
treatment operations, can utilize and benefit as well from the
disclosure of the present treatment slurry.
[0062] As used herein, "slurry" refers to an optionally flowable
mixture of particles dispersed in a fluid carrier. The terms
"flowable" or "pumpable" or "mixable" are used interchangeably
herein and refer to a fluid or slurry that has either a yield
stress less than 1000 Pa or low-shear (5.11 s.sup.-1) viscosity
less than 1000 Pa-s, and a dynamic apparent viscosity of less than
10 Pa-s (10,000 cP) at a shear rate 170 s.sup.-1, where yield
stress, low-shear viscosity and dynamic apparent viscosity are
measured at a temperature of 25.degree. C. unless another
temperature is specified explicitly or in context of use.
[0063] "Viscosity" as used herein unless otherwise indicated refers
to the apparent dynamic viscosity of a fluid at a temperature of
25.degree. C. and shear rate of 170 s.sup.-1. "Low-shear viscosity"
as used herein unless otherwise indicated refers to the apparent
dynamic viscosity of a fluid at a temperature of 25.degree. C. and
shear rate of 5.11 s.sup.-1. Yield stress and viscosity of the
treatment fluid are evaluated at 25.degree. C. in a Fann 35
rheometer with an R1B5F1 spindle, or an equivalent
rheometer/spindle arrangement, with shear rate ramped up to 255
s.sup.-1 (300 rpm) and back down to 0, an average of the two
readings at 2.55, 5.11, 85.0, 170 and 255 s.sup.-1 (3, 6, 100, 200
and 300 rpm) recorded as the respective shear stress, the apparent
dynamic viscosity is determined as the ratio of shear stress to
shear rate (.tau./.gamma.) at .gamma.=170 s.sup.-1, and the yield
stress (.tau..sub.0) (if any) is determined as the y-intercept
using a best fit of the Herschel-Buckley rheological model,
.tau.=.tau..sub.0+k(.gamma.).sup.n, where .tau. is the shear
stress, k is a constant, .gamma. is the shear rate and n is the
power law exponent. Where the power law exponent n is equal to 1,
the Herschel-Buckley fluid is known as a Bingham plastic. Yield
stress as used herein is synonymous with yield point and refers to
the stress required to initiate flow in a Bingham plastic or
Herschel-Buckley fluid system calculated as the y-intercept in the
manner described herein. A "yield stress fluid" refers to a
Herschel-Buckley fluid system, including Bingham plastics or
another fluid system in which an applied non-zero stress as
calculated in the manner described herein is required to initiate
fluid flow.
[0064] The following conventions with respect to slurry terms are
intended herein unless otherwise indicated explicitly or implicitly
by context. "Treatment fluid" or "fluid" (in context) refers to the
entire treatment fluid, including any proppant, subproppant
particles, liquid, gas etc. "Whole fluid," "total fluid" and "base
fluid" are used herein to refer to the fluid phase plus any
subproppant particles dispersed therein, but exclusive of proppant
particles. "Carrier," "fluid phase" or "liquid phase" refer to the
fluid or liquid that is present, which may comprise a continuous
phase and optionally one or more discontinuous fluid phases
dispersed in the continuous phase, including any solutes,
thickeners or colloidal particles only, exclusive of other solid
phase particles; reference to "water" in the slurry refers only to
water and excludes any particles, solutes, thickeners, colloidal
particles, etc.; reference to "aqueous phase" refers to a carrier
phase comprised predominantly of water, which may be a continuous
or dispersed phase. As used herein the terms "liquid" or "liquid
phase" encompass both liquids per se and supercritical fluids,
including any solutes dissolved therein.
[0065] The measurement or determination of the viscosity of the
liquid phase (as opposed to the treatment fluid or base fluid) may
be based on a direct measurement of the solids-free liquid, or a
calculation or correlation based on a measurement(s) of the
characteristics or properties of the liquid containing the solids,
or a measurement of the solids-containing liquid using a technique
where the determination of viscosity is not affected by the
presence of the solids. As used herein, solids-free for the
purposes of determining the viscosity of the liquid phase means in
the absence of non-colloidal particles larger than 1 micron such
that the particles do not affect the viscosity determination, but
in the presence of any submicron or colloidal particles that may be
present to thicken and/or form a gel with the liquid, i.e., in the
presence of ultrafine particles that can function as a thickening
agent. In some embodiments, a "low viscosity liquid phase" means a
viscosity less than about 300 mPa-s measured without any solids
greater than 1 micron at 170 s.sup.-1 and 25.degree. C.
[0066] In some embodiments, the treatment fluid may include a
continuous fluid phase, also referred to as an external phase, and
a discontinuous phase(s), also referred to as an internal phase(s),
which may be a fluid (liquid or gas) in the case of an emulsion,
foam or energized fluid, or which may be a solid in the case of a
slurry. The continuous fluid phase may be any matter that is
substantially continuous under a given condition. Examples of the
continuous fluid phase include, but are not limited to, water,
hydrocarbon, gas, liquefied gas, etc., which may include solutes,
e.g. the fluid phase may be a brine, and/or may include a brine or
other solution(s). In some embodiments, the fluid phase(s) may
optionally include a viscosifying and/or yield point agent and/or a
portion of the total amount of viscosifying and/or yield point
agent present. Some non-limiting examples of the fluid phase(s)
include hydratable gels (e.g., gels containing polysaccharides such
as guars (guar, hydroxypropyl guar, carboxymethyl guar,
carboxymethylhydroxypropyl guar, and the like), xanthan, diutan,
hydroxyethylcellulose, polyvinyl alcohol, other hydratable
polymers, colloids, etc.), a cross-linked hydratable gel, a
viscosified acid (e.g. gel-based), an emulsified acid (e.g. oil
outer phase), an energized fluid (e.g., an N.sub.2 or CO.sub.2
based foam), a viscoelastic surfactant (VES) viscosified fluid, and
an oil-based fluid including a gelled, foamed, or otherwise
viscosified oil.
[0067] The discontinuous phase if present in the treatment fluid
may be any particles (including fluid droplets) that are suspended
or otherwise dispersed in the continuous phase in a disjointed
manner. In this respect, the discontinuous phase can also be
referred to, collectively, as "particle" or "particulate" which may
be used interchangeably. As used herein, the term "particle" should
be construed broadly. For example, in some embodiments, the
particle(s) of the current application are solid such as proppant,
sands, ceramics, crystals, salts, etc.; however, in some other
embodiments, the particle(s) can be liquid, gas, foam, emulsified
droplets, etc. Moreover, in some embodiments, the particle(s) of
the current application are substantially stable and do not change
shape or form over an extended period of time, temperature, or
pressure; in some other embodiments, the particle(s) of the current
application are degradable, dissolvable, deformable, meltable,
sublimeable, or otherwise capable of being changed in shape, state,
or structure.
[0068] In certain embodiments, the particle(s), which may be
proppant or subproppant, is substantially round and spherical. In
some certain embodiments, the particle(s) is not substantially
spherical and/or round, e.g., it can have varying degrees of
sphericity and roundness, according to the API RP-60 sphericity and
roundness index. For example, the particle(s) may have an aspect
ratio, defined as the ratio of the longest dimension of the
particle to the shortest dimension of the particle, of more than 2,
3, 4, 5 or 6. Examples of such non-spherical particles include, but
are not limited to, fibers, flakes, discs, rods, stars, etc. All
such variations should be considered within the scope of the
current application.
[0069] The particles in the slurry in various embodiments may be
multimodal. As used herein multimodal refers to a plurality of
particle sizes or modes which each has a distinct size or particle
size distribution, e.g., proppant and fines. As used herein, the
terms distinct particle sizes, distinct particle size distribution,
or multi-modes or multimodal, mean that each of the plurality of
particles has a unique volume-averaged particle size distribution
(PSD) mode. That is, statistically, the particle size distributions
of different particles appear as distinct peaks (or "modes") in a
continuous probability distribution function. For example, a
mixture of two particles having normal distribution of particle
sizes with similar variability is considered a bimodal particle
mixture if their respective means differ by more than the sum of
their respective standard deviations, and/or if their respective
means differ by a statistically significant amount. In certain
embodiments, the particles contain a bimodal mixture of two
particles; in certain other embodiments, the particles contain a
trimodal mixture of three particles; in certain additional
embodiments, the particles contain a tetramodal mixture of four
particles; in certain further embodiments, the particles contain a
pentamodal mixture of five particles, and so on. Representative
references disclosing multimodal particle mixtures include U.S.
Pat. No. 5,518,996, U.S. Pat. No. 7,784,541, U.S. Pat. No.
7,789,146, U.S. Pat. No. 8,008,234, U.S. Pat. No. 8,119,574, U.S.
Pat. No. 8,210,249, US 2010/0300688, US 2012/0000641, US
2012/0138296, US 2012/0132421, US 2012/0111563, WO 2012/054456, US
2012/0305245, US 2012/0305254, US 2012/0132421, PCT/RU2011/000971
and U.S. Ser. No. 13/415,025, each of which are hereby incorporated
herein by reference.
[0070] "Solids" and "solids volume" refer to all solids present in
the slurry, including proppant and subproppant particles, including
particulate thickeners such as colloids and submicron particles.
"Solids-free" and similar terms generally exclude proppant and
subproppant particles, except particulate thickeners such as
colloids for the purposes of determining the viscosity of a
"solids-free" fluid. "Proppant" refers to particulates that are
used in well work-overs and treatments, such as hydraulic
fracturing operations, to hold fractures open following the
treatment, of a particle size mode or modes in the slurry having a
weight average mean particle size greater than or equal to about
100 microns, e.g., 140 mesh particles correspond to a size of 105
microns, unless a different proppant size is indicated in the claim
or a smaller proppant size is indicated in a claim depending
therefrom. "Gravel" refers to particles used in gravel packing, and
the term is synonymous with proppant as used herein. "Sub-proppant"
or "subproppant" refers to particles or particle size or mode
(including colloidal and submicron particles) having a smaller size
than the proppant mode(s); references to "proppant" exclude
subproppant particles and vice versa. In some embodiments, the
sub-proppant mode or modes each have a weight average mean particle
size less than or equal to about one-half of the weight average
mean particle size of a smallest one of the proppant modes, e.g., a
suspensive/stabilizing mode.
[0071] The proppant, when present, can be naturally occurring
materials, such as sand grains. The proppant, when present, can
also be man-made or specially engineered, such as coated (including
resin-coated) sand, modulus of various nuts, high-strength ceramic
materials like sintered bauxite, etc. In some embodiments, the
proppant of the current application, when present, has a density
greater than 2.45 g/mL, e.g., 2.5-2.8 g/mL, such as sand, ceramic,
sintered bauxite or resin coated proppant. In some embodiments, the
proppant of the current application, when present, has a density
less than or equal to 2.45 g/mL, such as less than about 1.60 g/mL,
less than about 1.50 g/mL, less than about 1.40 g/mL, less than
about 1.30 g/mL, less than about 1.20 g/mL, less than 1.10 g/mL, or
less than 1.00 g/mL, such as light/ultralight proppant from various
manufacturers, e.g., hollow proppant.
[0072] In some embodiments, the treatment fluid comprises an
apparent specific gravity greater than 1.3, greater than 1.4,
greater than 1.5, greater than 1.6, greater than 1.7, greater than
1.8, greater than 1.9, greater than 2, greater than 2.1, greater
than 2.2, greater than 2.3, greater than 2.4, greater than 2.5,
greater than 2.6, greater than 2.7, greater than 2.8, greater than
2.9, or greater than 3. The treatment fluid density can be selected
by selecting the specific gravity and amount of the dispersed
solids and/or adding a weighting solute to the aqueous phase, such
as, for example, a compatible organic or mineral salt. In some
embodiments, the aqueous or other liquid phase may have a specific
gravity greater than 1, greater than 1.05, greater than 1.1,
greater than 1.2, greater than 1.3, greater than 1.4, greater than
1.5, greater than 1.6, greater than 1.7, greater than 1.8, greater
than 1.9, greater than 2, greater than 2.1, greater than 2.2,
greater than 2.3, greater than 2.4, greater than 2.5, greater than
2.6, greater than 2.7, greater than 2.8, greater than 2.9, or
greater than 3, etc. In some embodiments, the aqueous or other
liquid phase may have a specific gravity less than 1. In
embodiments, the weight of the treatment fluid can provide
additional hydrostatic head pressurization in the wellbore at the
perforations or other fracture location, and can also facilitate
stability by lessening the density differences between the larger
solids and the whole remaining fluid. In other embodiments, a low
density proppant may be used in the treatment, for example,
lightweight proppant (apparent specific gravity less than 2.65)
having a density less than or equal to 2.5 g/mL, such as less than
about 2 g/mL, less than about 1.8 g/mL, less than about 1.6 g/mL,
less than about 1.4 g/mL, less than about 1.2 g/mL, less than 1.1
g/mL, or less than 1 g/mL. In other embodiments, the proppant or
other particles in the slurry may have a specific gravity greater
than 2.6, greater than 2.7, greater than 2.8, greater than 2.9,
greater than 3, etc.
[0073] "Stable" or "stabilized" or similar terms refer to a
stabilized treatment slurry (STS) wherein gravitational settling of
the particles is inhibited such that no or minimal free liquid is
formed, and/or there is no or minimal rheological variation among
strata at different depths in the STS, and/or the slurry may
generally be regarded as stable over the duration of expected STS
storage and use conditions, e.g., an STS that passes a stability
test or an equivalent thereof. In certain embodiments, stability
can be evaluated following different settling conditions, such as
for example static under gravity alone, or dynamic under a
vibratory influence, or dynamic-static conditions employing at
least one dynamic settling condition followed and/or preceded by at
least one static settling condition.
[0074] The static settling test conditions can include gravity
settling for a specified period, e.g., 24 hours, 48 hours, 72
hours, or the like, which are generally referred to with the
respective shorthand notation "24 h-static", "48 h-static" or "72 h
static". Dynamic settling test conditions generally indicate the
vibratory frequency and duration, e.g., 4 h@ 15 Hz (4 hours at 15
Hz), 8 h@5 Hz (8 hours at 5 Hz), or the like. Dynamic settling test
conditions are at a vibratory amplitude of 1 mm vertical
displacement unless otherwise indicated. Dynamic-static settling
test conditions will indicate the settling history preceding
analysis including the total duration of vibration and the final
period of static conditions, e.g., 4 h@15 Hz/20 h-static refers to
4 hours vibration followed by 20 hours static, or 8 h@15 Hz/10
d-static refers to 8 hours total vibration, e.g., 4 hours vibration
followed by 20 hours static followed by 4 hours vibration, followed
by 10 days of static conditions. In the absence of a contrary
indication, the designation "8 h@ 15 Hz/10 d-static" refers to the
test conditions of 4 hours vibration, followed by 20 hours static
followed by 4 hours vibration, followed by 10 days of static
conditions. In the absence of specified settling conditions, the
settling condition is 72 hours static. The stability settling and
test conditions are at 25.degree. C. unless otherwise
specified.
[0075] In certain embodiments, one stability test is referred to
herein as the "8 h@ 15 Hz/10 d-static STS stability test", wherein
a slurry sample is evaluated in a rheometer at the beginning of the
test and compared against different strata of a slurry sample
placed and sealed in a 152 mm (6 in.) diameter vertical
gravitational settling column filled to a depth of 2.13 m (7 ft),
vibrated at 15 Hz with a 1 mm amplitude (vertical displacement) two
4-hour periods the first and second settling days, and thereafter
maintained in a static condition for 10 days (12 days total
settling time). The 15 Hz/1 mm amplitude condition in this test is
selected to correspond to surface transportation and/or storage
conditions prior to the well treatment. At the end of the settling
period the depth of any free water at the top of the column is
measured, and samples obtained, in order from the top sampling port
down to the bottom, through 25.4-mm sampling ports located on the
settling column at 190 mm (6'3''), 140 mm (4'7''), 84 mm (2'9'')
and 33 mm (1'1''), and rheologically evaluated for viscosity and
yield stress as described above.
[0076] As mentioned above, various slurry stabilizing operations
may be employed to obtain one or more of the slurry stabilization
indicia. For example, decreasing the density difference between the
particle and the carrier fluid may be done in embodiments by
employing porous particles, including particles with an internal
porosity, i.e., hollow particles. However, the porosity may also
have a direct influence on the mechanical properties of the
particle, e.g., the elastic modulus, which may also decrease
significantly with an increase in porosity. In certain embodiments
employing particle porosity, care should be taken so that the crush
strength of the particles exceeds the maximum expected stress for
the particle, e.g., in the embodiments of proppants placed in a
fracture the overburden stress of the subterranean formation in
which it is to be used should not exceed the crush strength of the
proppants.
[0077] In embodiments, yield stress fluids and/or fluids having a
high low-shear viscosity are used to retard the motion of the
carrier fluid and thus retard particle settling. The gravitational
stress exerted by the particle at rest or descending slowly on the
fluid beneath it must generally exceed the yield stress of the
fluid to initiate fluid flow and thus settling onset, or just after
settling onset it must exceed the low-shear resistance to flow. For
a single particle of density 2.7 g/mL and diameter of 600 .mu.m
settling in a yield stress fluid phase of 1 g/mL, the critical
fluid yield stress, i.e., the minimum yield stress to prevent
settling onset, in this example is 1 Pa. The critical fluid yield
stress might be higher for larger particles, including particles
with size enhancement due to particle clustering, aggregation or
the like.
[0078] Increasing carrier fluid viscosity in a Newtonian fluid also
proportionally increases the resistance of the carrier fluid
motion. In some embodiments, the fluid carrier has a lower limit of
low-shear viscosity, determined at 5.11 s.sup.-1 and 25.degree. C.,
of at least about 1 Pa-s, or at least about 5 Pa-s, or at least
about 10 Pa-s, or at least about 25 Pa-s, or at least about 50
Pa-s, or at least about 75 Pa-s, or at least about 100 Pa-s, or at
least about 150 Pa-s. In some embodiments, the fluid carrier has a
lower limit of apparent dynamic viscosity, determined at 170
s.sup.-1 and 25.degree. C., of at least about 0.1 mPa-s, or at
least about 1 mPa-s, or at least about 10 mPa-s, or at least about
25 mPa-s, or at least about 50 mPa-s, or at least about 75 mPa-s,
or at least about 100 mPa-s, or at least about 150 mPa-s. A
disadvantage of increasing the viscosity is that as the viscosity
increases, the friction pressure for pumping the slurry generally
increases as well. In some embodiments, the fluid carrier has an
upper limit of low-shear viscosity, determined at 5.11 s.sup.-1 and
25.degree. C., of less than about 300 Pa-s, or less than about 150
Pa-s, or less than about 100 Pa-s, or less than about 75 Pa-s, or
less than about 50 Pa-s, or less than about 25 Pa-s, or less than
about 10 Pa-s. In some embodiments, the fluid carrier has an upper
limit of apparent dynamic viscosity, determined at 170 s.sup.-1 and
25.degree. C., of less than about 300 mPa-s, or less than about 150
mPa-s, or less than about 100 mPa-s, or less than about 75 mPa-s,
or less than about 50 mPa-s, or less than about 25 mPa-s, or less
than about 10 mPa-s. In embodiments, the low-shear and/or apparent
dynamic fluid phase viscosity ranges from any respective lower
limit to any respective higher upper limit.
[0079] In some embodiments, an agent may both viscosify and impart
yield stress characteristics, and in further embodiments may also
function as a friction reducer to reduce friction pressure losses
in pumping the treatment fluid. In embodiments, the liquid phase is
essentially free of viscosifier or comprises a viscosifier in an
amount ranging from 0.01 up to 2.4 g/L (0.08-20 lb/1000 gals) of
the fluid phase. The viscosifier can be a viscoelastic surfactant
(VES) or a hydratable gelling agent such as a polysaccharide, which
may be crosslinked. In embodiments, the liquid phase comprises a
hydratable gelling agent in an amount ranging from 0.01 up to 4.8
g/L (0.08-40 lb/1000 gals) of the fluid phase, or a VES in an
amount ranging from 0.01 up to 7.2 g/L (0.08-60 lb/1000 gals) of
the fluid phase. When using viscosifiers and/or yield stress
fluids, it may be useful to consider the need for and if necessary
implement a clean-up procedure, i.e., removal or inactivation of
the viscosifier and/or yield stress fluid during or following the
treatment procedure, since fluids with viscosifiers and/or yield
stresses may present clean up difficulties in some situations or if
not used correctly. In certain embodiments, clean up can be
effected using a breaker(s). In some embodiments, the slurry is
stabilized for storage and/or pumping or other use at the surface
conditions, and clean-up is achieved downhole at a later time and
at a higher temperature, e.g., for some formations, the temperature
difference between surface and downhole can be significant and
useful for triggering degradation of the viscosifier, the
particles, a yield stress agent or characteristic, and/or a
breaker. Thus in some embodiments, breakers that are either
temperature sensitive or time sensitive, either through delayed
action breakers or delay in mixing the breaker into the slurry, can
be useful.
[0080] In certain embodiments, the fluid may be stabilized by
introducing colloidal particles into the treatment fluid, such as,
for example, colloidal silica, which may function as a gellant
and/or thickener.
[0081] In addition or as an alternative to increasing the viscosity
of the carrier fluid (with or without density manipulation),
increasing the volume fraction of the particles in the treatment
fluid can also hinder movement of the carrier fluid. Where the
particles are not deformable, the particles interfere with the flow
of the fluid around the settling particle to cause hindered
settling. The addition of a large volume fraction of particles can
be complicated, however, by increasing fluid viscosity and pumping
pressure, and increasing the risk of loss of fluidity of the slurry
in the event of carrier fluid losses. In some embodiments, the
treatment fluid has a lower limit of apparent dynamic viscosity,
determined at 170 s.sup.-1 and 25.degree. C., of at least about 1
mPa-s, or at least about 10 mPa-s, or at least about 25 mPa-s, or
at least about 50 mPa-s, or at least about 75 mPa-s, or at least
about 100 mPa-s, or at least about 150 mPa-s, or at least about 300
mPa-s, and an upper limit of apparent dynamic viscosity, determined
at 170 s.sup.-1 and 25.degree. C., of less than about 500 mPa-s, or
less than about 300 mPa-s, or less than about 150 mPa-s, or less
than about 100 mPa-s, or less than about 75 mPa-s, or less than
about 50 mPa-s, or less than about 25 mPa-s, or less than about 10
mPa-s. In embodiments, the treatment fluid viscosity ranges from
any lower limit to any higher upper limit.
[0082] In embodiments, the treatment fluid may be stabilized by
introducing sufficient particles into the treatment fluid to
increase the SVF of the treatment fluid, e.g., to at least 0.5. In
a powder or particulated medium, the packed volume fraction (PVF)
is defined as the volume of space occupied by the particles (the
absolute volume) divided by the bulk volume, i.e., the total volume
of the particles plus the void space between them:
PVF=Particle volume/(Particle volume+Non-particle
Volume)=1-.phi.
For the purposes of calculating PVF and SVF herein, the particle
volume includes the volume of any colloidal and/or submicron
particles.
[0083] Here, the porosity, .phi., is the void fraction of the
powder pack. Unless otherwise specified the PVF of a particulated
medium is determined in the absence of overburden or other
compressive force that would deform the packed solids. The packing
of particles (in the absence of overburden) is a purely geometrical
phenomenon. Therefore, the PVF depends only on the size and the
shape of particles. The most ordered arrangement of monodisperse
spheres (spheres with exactly the same size in a compact hexagonal
packing) has a PVF of 0.74. However, such highly ordered
arrangements of particles rarely occur in industrial operations.
Rather, a somewhat random packing of particles is prevalent in
oilfield treatment. Unless otherwise specified, particle packing in
the current application means random packing of the particles. A
random packing of the same spheres has a PVF of 0.64. In other
words, the randomly packed particles occupy 64% of the bulk volume,
and the void space occupies 36% of the bulk volume. A higher PVF
can be achieved by preparing blends of particles that have more
than one particle size and/or a range(s) of particle sizes. The
smaller particles can fit in the void spaces between the larger
ones.
[0084] The PVF in embodiments can therefore be increased by using a
multimodal particle mixture, for example, coarse, medium and fine
particles in specific volume ratios, where the fine particles can
fit in the void spaces between the medium-size particles, and the
medium size particles can fit in the void space between the coarse
particles. For some embodiments of two consecutive size classes or
modes, the ratio between the mean particle diameters (d.sub.50) of
each mode may be between 7 and 10. In such cases, the PVF can
increase up to 0.95 in some embodiments. By blending coarse
particles (such as proppant) with other particles selected to
increase the PVF, only a minimum amount of fluid phase (such as
water) is needed to render the treatment fluid pumpable. Such
concentrated suspensions (i.e. slurry) tend to behave as a porous
solid and may shrink under the force of gravity. This is a hindered
settling phenomenon as discussed above and, as mentioned, the
extent of solids-like behavior generally increases with the slurry
solid volume fraction (SVF), which is given as
SVF=Particle volume/(Particle volume+Liquid volume)
[0085] It follows that proppant or other large particle mode
settling in multimodal embodiments can if desired be minimized
independently of the viscosity of the continuous phase. Therefore,
in some embodiments little or no viscosifier and/or yield stress
agent, e.g., a gelling agent, is required to inhibit settling and
achieve particle transport, such as, for example, less than 2.4
g/L, less than 1.2 g/L, less than 0.6 g/L, less than 0.3 g/L, less
than 0.15 g/L, less than 0.08 g/L, less than 0.04 g/L, less than
0.2 g/L or less than 0.1 g/L of viscosifier may be present in the
STS.
[0086] It is helpful for an understanding of the current
application to consider the amounts of particles present in the
slurries of various embodiments of the treatment fluid. The minimum
amount of fluid phase necessary to make a homogeneous slurry blend
is the amount required to just fill all the void space in the PVF
with the continuous phase, i.e., when SVF=PVF. However, this blend
may not be flowable since all the solids and liquid may be locked
in place with no room for slipping and mobility. In flowable system
embodiments, SVF may be lower than PVF, e.g., SVF/PVF.ltoreq.0.99.
In this condition, in a stabilized treatment slurry, essentially
all the voids are filled with excess liquid to increase the spacing
between particles so that the particles can roll or flow past each
other. In some embodiments, the higher the PVF, the lower the
SVF/PVF ratio should be to obtain a flowable slurry.
[0087] FIG. 1 shows a slurry state progression chart for a system
600 having a particle mix with added fluid phase. The first fluid
602 does not have enough liquid added to fill the pore spaces of
the particles, or in other words the SVF/PVF is greater than 1.0.
The first fluid 602 is not flowable. The second fluid 604 has just
enough fluid phase to fill the pore spaces of the particles, or in
other words the SVF/PVF is equal to 1.0. Testing determines whether
the second fluid 604 is flowable and/or pumpable, but a fluid with
an SVF/PVF of 1.0 is generally not flowable or barely flowable due
to an excessive apparent viscosity and/or yield stress. The third
fluid 606 has slightly more fluid phase than is required to fill
the pore spaces of the particles, or in other words the SVF/PVF is
just less than 1.0. A range of SVF/PVF values less than 1.0 will
generally be flowable and/or pumpable or mixable, and if it does
not contain too much fluid phase (and/or contains an added
viscosifier) the third fluid 606 is stable. The values of the range
of SVF/PVF values that are pumpable, flowable, mixable, and/or
stable are dependent upon, without limitation, the specific
particle mixture, fluid phase viscosity, the PVF of the particles,
and the density of the particles. Simple laboratory testing of the
sort ordinarily performed for fluids before fracturing treatments
can readily determine the stability (e.g., the STS stability test
as described herein) and flowability (e.g., apparent dynamic
viscosity at 170 s.sup.-1 and 25.degree. C. of less than about
10,000 mPa-s).
[0088] The fourth fluid 608 shown in FIG. 1 has more fluid phase
than the third fluid 606, to the point where the fourth fluid 608
is flowable but is not stabilized and settles, forming a layer of
free fluid phase at the top (or bottom, depending upon the
densities of the particles in the fourth fluid 608). The amount of
free fluid phase and the settling time over which the free fluid
phase develops before the fluid is considered unstable are
parameters that depend upon the specific circumstances of a
treatment, as noted above. For example, if the settling time over
which the free liquid develops is greater than a planned treatment
time, then in one example the fluid would be considered stable.
Other factors, without limitation, that may affect whether a
particular fluid remains stable include the amount of time for
settling and flow regimes (e.g. laminar, turbulent, Reynolds number
ranges, etc.) of the fluid flowing in a flow passage of interest or
in an agitated vessel, e.g., the amount of time and flow regimes of
the fluid flowing in the wellbore, fracture, etc., and/or the
amount of fluid leakoff occurring in the wellbore, fracture, etc. A
fluid that is stable for one fracturing treatment may be unstable
for a second fracturing treatment. The determination that a fluid
is stable at particular conditions may be an iterative
determination based upon initial estimates and subsequent modeling
results. In some embodiments, the stabilized treatment fluid passes
the STS test described herein.
[0089] FIG. 2 shows a data set 700 of various essentially Newtonian
fluids without any added viscosifiers and without any yield stress,
which were tested for the progression of slurry state on a plot of
SVF/PVF as a function of PVF. The fluid phase in the experiments
was water and the solids had specific gravity 2.6 g/mL. Data points
702 indicated with a triangle were values that had free water in
the slurry, data points 704 indicated with a circle were slurriable
fluids that were mixable without excessive free water, and data
points 706 indicated with a diamond were not easily mixable
liquid-solid mixtures. The data set 700 includes fluids prepared
having a number of discrete PVF values, with liquid added until the
mixture transitions from not mixable to a slurriable fluid, and
then further progresses to a fluid having excess settling. At an
example for a solids mixture with a PVF value near PVF=0.83, it was
observed that around an SVF/PVF value of 0.95 the fluid transitions
from an unmixable mixture to a slurriable fluid. At around an
SVF/PVF of 0.7, the fluid transitions from a stable slurry to an
unstable fluid having excessive settling. It can be seen from the
data set 700 that the compositions can be defined approximately
into a non-mixable region 710, a slurriable region 712, and a
settling region 714.
[0090] FIG. 2 shows the useful range of SVF and PVF for slurries in
embodiments without gelling agents. In some embodiments, the SVF is
less than the PVF, or the ratio SVF/PVF is within the range from
about 0.6 or about 0.65 to about 0.95 or about 0.98. Where the
liquid phase has a viscosity less than 10 mPa-s or where the
treatment fluid is water essentially free of thickeners, in some
embodiments PVF is greater than 0.72 and a ratio of SVF/PVF is
greater than about 1-2.1*(PVF-0.72) for stability (non-settling).
Where the PVF is greater than 0.81, in some embodiments a ratio of
SVF/PVF may be less than 1-2.1*(PVF-0.81) for mixability
(flowability). Adding thickening or suspending agents, or solids
that perform this function such as calcium carbonate or colloids,
i.e., to increase viscosity and/or impart a yield stress, in some
embodiments allows fluids otherwise in the settling area 714
embodiments (where SVF/PVF is less than or equal to about
1-2.1*(PVF-0.72)) to also be useful as an STS or in applications
where a non-settling, slurriable/mixable slurry is beneficial,
e.g., where the treatment fluid has a viscosity greater than 10
mPa-s, greater than 25 mPa-s, greater than 50 mPa-s, greater than
75 mPa-s, greater than 100 mPa-s, greater than 150 mPa-s, or
greater than 300 mPa-s; and/or a yield stress greater than 0.1 Pa,
greater than 0.5 Pa, greater than 1 Pa, greater than 10 Pa or
greater than 20 Pa.
[0091] Introducing high-aspect ratio particles into the treatment
fluid, e.g., particles having an aspect ratio of at least 6,
represents additional or alternative embodiments for stabilizing
the treatment fluid. Examples of such non-spherical particles
include, but are not limited to, fibers, flakes, discs, rods,
stars, etc., as described in, for example, U.S. Pat. No. 7,275,596,
US 2008/0196896, which are hereby incorporated herein by reference.
In certain embodiments, introducing ciliated or coated proppant
into the treatment fluid may stabilize or help stabilize the
treatment fluid.
[0092] Proppant or other particles coated with a hydrophilic
polymer can make the particles behave like larger particles and/or
more tacky particles in an aqueous medium. The hydrophilic coating
on a molecular scale may resemble ciliates, i.e., proppant
particles to which hairlike projections have been attached to or
formed on the surfaces thereof. Herein, hydrophilically coated
proppant particles are referred to as "ciliated or coated
proppant." Hydrophilically coated proppants and methods of
producing them are described, for example, in WO 2011-050046, U.S.
Pat. No. 5,905,468, U.S. Pat. No. 8,227,026 and U.S. Pat. No.
8,234,072, which are hereby incorporated herein by reference.
[0093] In some additional or alternative embodiment, the STS system
may have the benefit that the smaller particles in the voids of the
larger particles act as slip additives like mini-ball bearings,
allowing the particles to roll past each other without any
requirement for relatively large spaces between particles. This
property can be demonstrated in some embodiments by the flow of the
STS through a relatively small slot orifice with respect to the
maximum diameter of the largest particle mode of the STS, e.g., a
slot orifice less than 6 times the largest particle diameter,
without bridging at the slot, i.e., the slurry flowed out of the
slot has an SVF that is at least 90% of the SVF of the STS supplied
to the slot. In contrast, the slickwater technique requires a ratio
of perforation diameter to proppant diameter of at least 6, and
additional enlargement for added safety to avoid screen out usually
dictates a ratio of at least 8 or 10 and does not allow high
proppant loadings.
[0094] In embodiments, the flowability of the STS through narrow
flow passages such as perforations and fractures is similarly
facilitated, allowing a smaller ratio of perforation diameter
and/or fracture height to proppant size that still provides
transport of the proppant through the perforation and/or to the tip
of the fracture, i.e., improved flowability of the proppant in the
fracture, e.g., in relatively narrow fracture widths, and improved
penetration of the proppant-filled fracture extending away from the
wellbore into the formation. These embodiments provide a relatively
longer proppant-filled fracture prior to screenout relative to
slickwater or high-viscosity fluid treatments.
[0095] As used herein, the "minimum slot flow test ratio" refers to
a test wherein an approximately 100 mL slurry specimen is loaded
into a fluid loss cell with a bottom slot opened to allow the test
slurry to come out, with the fluid pushed by a piston using water
or another hydraulic fluid supplied with an ISCO pump or equivalent
at a rate of 20 mL/min, wherein a slot at the bottom of the cell
can be adjusted to different openings at a ratio of slot width to
largest particle mode diameter less than 6, and wherein the maximum
slot flow test ratio is taken as the lowest ratio observed at which
50 vol % or more of the slurry specimen flows through the slot
before bridging and a pressure increase to the maximum gauge
pressure occurs. In some embodiments, the STS has a minimum slot
flow test ratio less than 6, or less than 5, or less than 4, or
less than 3, or a range of 2 to 6, or a range of 3 to 5.
[0096] Because of the relatively low water content (high SVF) of
some embodiments of the STS, fluid loss from the STS may be a
concern where flowability is important and SVF should at least be
held lower than PVF, or considerably lower than PVF in some other
embodiments. In conventional hydraulic fracturing treatments, there
are two main reasons that a high volume of fluid and high amount of
pumping energy have to be used, namely proppant transport and fluid
loss. To carry the proppant to a distant location in a fracture,
the treatment fluid has to be sufficiently turbulent (slickwater)
or viscous (gelled fluid). Even so, only a low concentration of
proppant is typically included in the treatment fluid to avoid
settling and/or screen out. Moreover, when a fluid is pumped into a
formation to initiate or propagate a fracture, the fluid pressure
will be higher than the formation pressure, and the liquid in the
treatment fluid is constantly leaking off into the formation. This
is especially the case for slickwater operations. The fracture
creation is a balance between the fluid loss and new volume
created. As used herein, "fracture creation" encompasses either or
both the initiation of fractures and the propagation or growth
thereof. If the liquid injection rate is lower than the fluid loss
rate, the fracture cannot be grown and becomes packed off.
Therefore, traditional hydraulic fracturing operations are not
efficient in creating fractures in the formation.
[0097] In some embodiments of the STS herein where the SVF is high,
even a small loss of carrier fluid may result in a loss of
flowability of the treatment fluid, and in some embodiments it is
therefore undertaken to guard against excessive fluid loss from the
treatment fluid, at least until the fluid and/or proppant reaches
its ultimate destination. In embodiments, the STS may have an
excellent tendency to retain fluid and thereby maintain
flowability, i.e., it has a low leakoff rate into a porous or
permeable surface with which it may be in contact. According to
some embodiments of the current application, the treatment fluid is
formulated to have very good leakoff control characteristics, i.e.,
fluid retention to maintain flowability. The good leak control can
be achieved by including a leakoff control system in the treatment
fluid of the current application, which may comprise one or more of
high viscosity, low viscosity, a fluid loss control agent,
selective construction of a multi-modal particle system in a
multimodal fluid (MMF) or in a stabilized multimodal fluid (SMMF),
or the like, or any combination thereof.
[0098] As discussed in the examples below and as shown in FIG. 3,
the leakoff of embodiments of a treatment fluid of the current
application was an order of magnitude less than that of a
conventional crosslinked fluid. It should be noted that the leakoff
characteristic of a treatment fluid is dependent on the
permeability of the formation to be treated. Therefore, a treatment
fluid that forms a low permeability filter cake with good leakoff
characteristic for one formation may or may not be a treatment
fluid with good leakoff for another formation. Conversely, certain
embodiments of the treatment fluids of the current application form
low permeability filter cakes that have substantially superior
leakoff characteristics such that they are not dependent on the
substrate permeability provided the substrate permeability is
higher than a certain minimum, e.g., at least 1 mD.
[0099] In certain embodiments herein, the STS comprises a packed
volume fraction (PVF) greater than a slurry solids volume fraction
(SVF), and has a spurt loss value (Vspurt) less than 10 vol % of a
fluid phase of the stabilized treatment fluid or less than 50 vol %
of an excess fluid phase (Vspurt<0.50*(PVF-SVF), where the
"excess fluid phase" is taken as the amount of fluid in excess of
the amount present at the condition SVF=PVF, i.e., excess fluid
phase=PVF-SVF).
[0100] In some embodiments the treatment fluid comprises an STS
also having a very low leakoff rate. For example, the total leakoff
coefficient may be about 3.times.10.sup.-4 m/min.sup.1/2 (10.sup.-3
ft/min.sup.1/2) or less, or about 3.times.10.sup.-5 m/min.sup.1/2
(10.sup.-4 ft/min.sup.1/2) or less. As used herein, Vspurt and the
total leak-off coefficient Cw are determined by following the
static fluid loss test and procedures set forth in Section 8-8.1,
"Fluid loss under static conditions," in Reservoir Stimulation,
3.sup.rd Edition, Schlumberger, John Wiley & Sons, Ltd., pp.
8-23 to 8-24, 2000, in a filter-press cell using ceramic disks
(FANN filter disks, part number 210538) saturated with 2% KCl
solution and covered with filter paper and test conditions of
ambient temperature (25.degree. C.), a differential pressure of
3.45 MPa (500 psi), 100 ml sample loading, and a loss collection
period of 60 minutes, or an equivalent testing procedure. In some
embodiments of the current application, the treatment fluid has a
fluid loss value of less than 10 g in 30 min when tested on a core
sample with 1000 mD porosity. In some embodiments of the current
application, the treatment fluid has a fluid loss value of less
than 8 g in 30 min when tested on a core sample with 1000 mD
porosity. In some embodiments of the current application, the
treatment fluid has a fluid loss value of less than 6 g in 30 min
when tested on a core sample with 1000 mD porosity. In some
embodiments of the current application, the treatment fluid has a
fluid loss value of less than 2 g in 30 min when tested on a core
sample with 1000 mD porosity.
[0101] The unique low to no fluid loss property allows the
stabilized treatment fluid to be pumped at a low rate or pumping
stopped (static) with a low risk of screen out. In embodiments, the
low fluid loss characteristic may be obtained by including a
leak-off control agent, such as, for example, particulated loss
control agents (in some embodiments less than 1 micron or 0.05-0.5
microns), graded PSD or multimodal particles, polymers, latex,
fiber, etc. As used herein, the terms leak-off control agent, fluid
loss control agent and similar refer to additives that inhibit
fluid loss from the slurry into a permeable formation.
[0102] As representative leakoff control agents, which may be used
alone or in a multimodal fluid, there may be mentioned latex
dispersions, water soluble polymers, submicron particulates,
particulates with an aspect ratio higher than 1, or higher than 6,
combinations thereof and the like, such as, for example,
crosslinked polyvinyl alcohol microgel. The fluid loss agent can
be, for example, a latex dispersion of polyvinylidene chloride,
polyvinyl acetate, polystyrene-co-butadiene; a water soluble
polymer such as hydroxyethylcellulose (HEC), guar, copolymers of
polyacrylamide and their derivatives; particulate fluid loss
control agents in the size range of 30 nm to 1 micron, such as
.gamma.-alumina, colloidal silica, CaCO.sub.3, SiO.sub.2, bentonite
etc.; particulates with different shapes such as glass fibers,
flakes, films; and any combination thereof or the like. Fluid loss
agents can if desired also include or be used in combination with
acrylamido-methyl-propane sulfonate polymer (AMPS). In embodiments,
the leak-off control agent comprises a reactive solid, e.g., a
hydrolysable material such as PGA, PLA or the like; or it can
include a soluble or solubilizable material such as a wax, an
oil-soluble resin, or another material soluble in hydrocarbons, or
calcium carbonate or another material soluble at low pH; and so on.
In embodiments, the leak-off control agent comprises a reactive
solid selected from ground quartz, oil soluble resin, degradable
rock salt, clay, zeolite or the like. In other embodiments, the
leak-off control agent comprises one or more of magnesium
hydroxide, magnesium carbonate, magnesium calcium carbonate,
calcium carbonate, aluminum hydroxide, calcium oxalate, calcium
phosphate, aluminum metaphosphate, sodium zinc potassium
polyphosphate glass, and sodium calcium magnesium polyphosphate
glass, or the like.
[0103] The treatment fluid may additionally or alternatively
include, without limitation, friction reducers, clay stabilizers,
biocides, crosslinkers, gas generating agents, breakers, corrosion
inhibitors, and/or proppant flowback control additives. The
treatment fluid may further include a product formed from
degradation, hydrolysis, hydration, chemical reaction, or other
process that occur during preparation or operation.
[0104] In certain embodiments herein, the STS may be prepared by
combining the particles, such as proppant if present and
subproppant, the carrier liquid and any additives to form a
proppant-containing treatment fluid; and stabilizing the
proppant-containing treatment fluid. The combination and
stabilization may occur in any order or concurrently in single or
multiple stages in a batch, semi-batch or continuous operation. For
example, in some embodiments, the base fluid may be prepared from
the subproppant particles, the carrier liquid and other additives,
and then the base fluid combined with the proppant.
[0105] The treatment fluid may be prepared on location, e.g., at
the wellsite when and as needed using conventional treatment fluid
blending equipment. FIG. 4 shows a wellsite equipment configuration
10 for a fracture treatment job according to some embodiments using
the principles disclosed herein, for a land-based fracturing
operation. The proppant is contained in sand trailers 10A, 10B.
Water tanks 12A, 12B, 12C, 12D are arranged along one side of the
operation site. Hopper 14 receives sand from the sand trailers 10A,
10B and distributes it into the mixer truck 16. Blender 18 is
provided to blend the carrier medium (such as brine, viscosified
fluids, etc.) with the proppant, i.e., "on the fly," and then the
slurry is discharged to manifold 31. The final mixed and blended
slurry, also called frac fluid, is then transferred to the pump
trucks 22A, 22B, 22C, 22D, and routed at treatment pressure through
treating line 34 to rig 35, and then pumped downhole. This
configuration eliminates the additional mixer truck(s), pump
trucks, blender(s), manifold(s) and line(s) normally required for
slickwater fracturing operations, and the overall footprint is
considerably reduced.
[0106] FIG. 5 shows further embodiments of the wellsite equipment
configuration with the additional feature of delivery of pump-ready
treatment fluid delivered to the wellsite in trailers 10A to 10D
and further elimination of the mixer, hopper 14, and/or blender 18.
In some embodiments the treatment fluid is prepared offsite and
pre-mixed with proppant and other additives, or with some or all of
the additives except proppant, such as in a system described in
co-pending co-assigned patent applications with application Ser.
No. 13/415,025, filed on Mar. 8, 2012, and application Ser. No.
13/487,002, filed on Jun. 1, 2012, the entire contents of which are
incorporated herein by reference in their entireties. As used
herein, the term "pump-ready" should be understood broadly. In
certain embodiments, a pump-ready treatment fluid means the
treatment fluid is fully prepared and can be pumped downhole
without being further processed. In some other embodiments, the
pump-ready treatment fluid means the fluid is substantially ready
to be pumped downhole except that a further dilution may be needed
before pumping or one or more minor additives need to be added
before the fluid is pumped downhole. In such an event, the
pump-ready treatment fluid may also be called a pump-ready
treatment fluid precursor. In some further embodiments, the
pump-ready treatment fluid may be a fluid that is substantially
ready to be pumped downhole except that certain incidental
procedures are applied to the treatment fluid before pumping, such
as low-speed agitation, heating or cooling under exceptionally cold
or hot climate, etc.
[0107] In certain embodiments herein, for example in low water
fracturing and frac-and-pack operations, the STS comprises proppant
and a fluid phase at a volumetric ratio of the fluid phase (Vfluid)
to the proppant (Vprop) equal to or less than 3. In embodiments,
Vfluid/Vprop is equal to or less than 2.5. In embodiments,
Vfluid/Vprop is equal to or less than 2. In embodiments,
Vfluid/Vprop is equal to or less than 1.5. In embodiments,
Vfluid/Vprop is equal to or less than 1.25. In embodiments,
Vfluid/Vprop is equal to or less than 1. In embodiments,
Vfluid/Vprop is equal to or less than 0.75. In embodiments,
Vfluid/Vprop is equal to or less than 0.7. In embodiments,
Vfluid/Vprop is equal to or less than 0.6. In embodiments,
Vfluid/Vprop is equal to or less than 0.5. In embodiments,
Vfluid/Vprop is equal to or less than 0.4. In embodiments,
Vfluid/Vprop is equal to or less than 0.35. In embodiments,
Vfluid/Vprop is equal to or less than 0.3. In embodiments,
Vfluid/Vprop is equal to or less than 0.25. In embodiments,
Vfluid/Vprop is equal to or less than 0.2. In embodiments,
Vfluid/Vprop is equal to or less than 0.1. In embodiments,
Vfluid/Vprop may be sufficiently high such that the STS is
flowable. In some embodiments, the ratio Vfluid/Vprop is equal to
or greater than 0.05, equal to or greater than 0.1, equal to or
greater than 0.15, equal to or greater than 0.2, equal to or
greater than 0.25, equal to or greater than 0.3, equal to or
greater than 0.35, equal to or greater than 0.4, equal to or
greater than 0.5, or equal to or greater than 0.6, or within a
range from any lower limit to any higher upper limit mentioned
above.
[0108] Nota bene, the STS may optionally comprise subproppant
particles in the whole fluid which are not reflected in the
Vfluid/Vprop ratio, which is merely a ratio of the liquid phase
(sans solids) volume to the proppant volume. This ratio is useful,
in the context of the STS where the liquid phase is aqueous, as the
ratio of water to proppant, i.e., Vwater/Vprop. In contrast, the
"ppa" designation refers to pounds proppant added per gallon of
base fluid (liquid plus subproppant particles), which can be
converted to an equivalent volume of proppant added per volume of
base fluid if the specific gravity of the proppant is known, e.g.,
2.65 in the case of quartz sand embodiments, in which case 1
ppa=0.12 kg/L=45 mL/L; whereas "ppg" (pounds of proppant per gallon
of treatment fluid) and "ppt" (pounds of additive per thousand
gallons of treatment fluid) are based on the volume of the
treatment fluid (liquid plus proppant and subproppant particles),
which for quartz sand embodiments (specific gravity=2.65) also
convert to 1 ppg=1000 ppt=0.12 kg/L=45 mL/L. The ppa, ppg and ppt
nomenclature and their metric or SI equivalents are useful for
considering the weight ratios of proppant or other additive(s) to
base fluid (water or other fluid and subproppant) and/or to
treatment fluid (water or other fluid plus proppant plus
subproppant). The ppt nomenclature is generally used in embodiments
reference to the concentration by weight of low concentration
additives other than proppant, e.g., 1 ppt=0.12 g/L.
[0109] In embodiments, the proppant-containing treatment fluid
comprises 0.27 L or more of proppant volume per liter of treatment
fluid (corresponding to 720 g/L (6 ppg) in embodiments where the
proppant has a specific gravity of 2.65), or 0.36 L or more of
proppant volume per liter of treatment fluid (corresponding to 960
g/L (8 ppg) in embodiments where the proppant has a specific
gravity of 2.65), or 0.4 L or more of proppant volume per liter of
treatment fluid (corresponding to 1.08 kg/L (9 ppg) in embodiments
where the proppant has a specific gravity of 2.65), or 0.44 L or
more of proppant volume per liter of treatment fluid (corresponding
to 1.2 kg/L (10 ppg) in embodiments where the proppant has a
specific gravity of 2.65), or 0.53 L or more of proppant volume per
liter of treatment fluid (corresponding to 1.44 kg/L (12 ppg) in
embodiments where the proppant has a specific gravity of 2.65), or
0.58 L or more of proppant volume per liter of treatment fluid
(corresponding to 1.56 kg/L (13 ppg) in embodiments where the
proppant has a specific gravity of 2.65), or 0.62 L or more of
proppant volume per liter of treatment fluid (corresponding to 1.68
kg/L (14 ppg) in embodiments where the proppant has a specific
gravity of 2.65), or 0.67 L or more of proppant volume per liter of
treatment fluid (corresponding to 1.8 kg/L (15 ppg) in embodiments
where the proppant has a specific gravity of 2.65), or 0.71 L or
more of proppant volume per liter of treatment fluid (corresponding
to 1.92 kg/L (16 ppg) in embodiments where the proppant has a
specific gravity of 2.65).
[0110] As used herein, in some embodiments, "high proppant loading"
means, on a mass basis, more than 1.0 kg proppant added per liter
of whole fluid including any sub-proppant particles (8 ppa), or on
a volumetric basis, more than 0.36 L proppant added per liter of
whole fluid including any sub-proppant particles, or a combination
thereof. In some embodiments, the treatment fluid comprises more
than 1.1 kg proppant added per liter of whole fluid including any
sub-proppant particles (9 ppa), or more than 1.2 kg proppant added
per liter of whole fluid including any sub-proppant particles (10
ppa), or more than 1.44 kg proppant added per liter of whole fluid
including any sub-proppant particles (12 ppa), or more than 1.68 kg
proppant added per liter of whole fluid including any sub-proppant
particles (14 ppa), or more than 1.92 kg proppant added per liter
of whole fluid including any sub-proppant particles (16 ppa), or
more than 2.4 kg proppant added per liter of fluid including any
sub-proppant particles (20 ppa), or more than 2.9 kg proppant added
per liter of fluid including any sub-proppant particles (24 ppa).
In some embodiments, the treatment fluid comprises more than 0.45 L
proppant added per liter of whole fluid including any sub-proppant
particles, or more than 0.54 L proppant added per liter of whole
fluid including any sub-proppant particles, or more than 0.63 L
proppant added per liter of whole fluid including any sub-proppant
particles, or more than 0.72 L proppant added per liter of whole
fluid including any sub-proppant particles, or more than 0.9 L
proppant added per liter of whole fluid including any sub-proppant
particles.
[0111] In some embodiments, the water content in the fracture
treatment fluid formulation is low, e.g., less than 30% by volume
of the treatment fluid, the low water content enables low overall
water volume to be used, relative to a slickwater fracture job for
example, to place a similar amount of proppant or other solids,
with low to essentially zero fluid infiltration into the formation
matrix and/or with low to zero flowback after the treatment, and
less chance for fluid to migrate away from the hydrocarbon
reservoir into adjacent intervals. The low flowback leads to less
delay in producing the stimulated formation, which can be placed
into production with a shortened clean up stage or in some cases
immediately without a separate flowback recovery operation.
[0112] In embodiments where the fracturing treatment fluid also has
a low viscosity and a relatively high SVF, e.g., 40, 50, 60 or 70%
or more, the fluid can in some surprising embodiments be very
flowable (low viscosity) and can be pumped using standard well
treatment equipment. With a high volumetric ratio of proppant to
water, e.g., greater than about 1.0, these embodiments represent a
breakthrough in water efficiency in fracture treatments.
Embodiments of a low water content in the treatment fluid certainly
results in correspondingly low fluid volumes to infiltrate the
formation, and importantly, no or minimal flowback during fracture
cleanup and when placed in production. In the solid pack, as well
as on formation surfaces and in the formation matrix, water can be
retained due to a capillary and/or surface wetting effect. In
embodiments, the solids pack obtained from an STS with multimodal
solids can retain a larger proportion of water than conventional
proppant packs, further reducing the amount of water flowback. In
some embodiments, the water retention capability of the
fracture-formation system can match or exceed the amount of water
injected into the formation, and there may thus be no or very
little water flowback when the well is placed in production.
[0113] In some specific embodiments, the proppant laden treatment
fluid comprises an excess of a low viscosity continuous fluid
phase, e.g., a liquid phase, and a multimodal particle phase, e.g.
solids phase, comprising high proppant loading with one or more
proppant modes for fracture conductivity and at least one
sub-proppant mode to facilitate proppant injection. As used herein
an excess of the continuous fluid phase implies that the fluid
volume fraction in a slurry (1-SVF) exceeds the void volume
fraction (1-PVF) of the solids in the slurry, i.e., SVF<PVF.
Solids in the slurry in embodiments may comprise both proppant and
one or more sub-proppant particle modes. In embodiments, the
continuous fluid phase is a liquid phase.
[0114] In some embodiments, the STS is prepared by combining the
proppant and a fluid phase having a viscosity less than 300 mPa-s
(170 s.sup.-1, 25 C) to form the proppant-containing treatment
fluid, and stabilizing the proppant-containing treatment fluid.
Stabilizing the treatment fluid is described above. In some
embodiments, the proppant-containing treatment fluid is prepared to
comprise a viscosity between 0.1 and 300 mPa-s (170 s.sup.-1, 25 C)
and a yield stress between 1 and 20 Pa (2.1-42 lb.sub.f/ft.sup.2).
In some embodiments, the proppant-containing treatment fluid
comprises 0.36 L or more of proppant volume per liter of
proppant-containing treatment fluid (8 ppa proppant equivalent
where the proppant has a specific gravity of 2.6), a viscosity
between 0.1 and 300 mPa-s (170 s.sup.-1, 25 C), a solids phase
having a packed volume fraction (PVF) greater than 0.72, a slurry
solids volume fraction (SVF) less than the PVF and a ratio of
SVF/PVF greater than about 1-2.1*(PVF-0.72).
[0115] In some embodiments, e.g., for delivery of a fracturing
stage, the STS comprises a volumetric proppant/treatment fluid
ratio (including proppant and sub-proppant solids) in a main stage
of at least 0.27 L/L (6 ppg at sp.gr. 2.65), or at least 0.36 L/L
(8 ppg), or at least 0.44 L/L (10 ppg), or at least 0.53 L/L (12
ppg), or at least 0.58 L/L (13 ppg), or at least 0.62 L/L (14 ppg),
or at least 0.67 L/L (15 ppg), or at least 0.71 L/L (16 ppg).
[0116] In some embodiments, the hydraulic fracture treatment may
comprise an overall volumetric proppant/water ratio of at least
0.13 L/L (3 ppg at sp. gr. 2.65), or at least 0.18 L/L (4 ppg), or
at least 0.22 L/L (5 ppg), or at least 0.26 L/L (6 ppg), or at
least 0.38 L/L (8 ppg), or at least 0.44 L/L (10 ppg), or at least
0.53 L/L (12 ppg), or at least 0.58 L/L (13 ppg). Note that
subproppant particles are not a factor in the determination of the
proppant-water ratio.
[0117] As used herein, a "destabilized" STS refers to a previously
stable or stabilized treatment slurry which has been modified so
that it is no longer a stable slurry as defined above, or includes
discontinuous regions of consolidated slurry solids that are no
longer stable or no longer flowable within a network of flow
channels, wherein the flow channels comprise free fluid, flowable
slurry, a permeable solids matrix relative to the discontinuous
regions of consolidated slurry solids, or a combination. As used
herein, the term "destabilizing system" refers to one or a
combination chemical and/or physical agent(s) that render the STS
destabilized, and in some embodiments refers to such an agent or
combination of agents that precipitates the solids from the slurry
into consolidated, immobilized proppant pillars. In embodiments,
the destabilizing system may be present in whole or in part in a
stabilized treatment slurry, which may or may not be the same STS
containing proppant, or in another treatment fluid such as a
non-stabilized slurry or a solution, injected in one or more
before, between, concurrently with or after one or more stages of
the stabilized slurry to be destabilized.
[0118] As used herein, the term "channels" refers to interconnected
conductive passageways formed between the proppant pillars in the
proppant-fracture structure. "Open channels" present in some
embodiments are distinct from "permeable channels," which refer to
channels containing proppant pack comprising a network of
interstitial passages between individual proppant particles in a
proppant matrix, in that the open channels fully extend between
opposing fracture faces, free of obstruction by proppant or other
flow-impeding structures, and exist outside the proppant matrix,
laterally bounded by the proppant pillars. Such open channels in
embodiments may have a hydraulic radius, and hence a hydraulic
conductivity, that is at least an order of magnitude larger than
that of interstitial flow passages through the proppant matrix. In
some embodiments, the pillars may also be conductive, including as
or nearly as conductive as the channels between the pillars.
"Pillars" as used herein refer to either or both consolidated
and/or less conductive immobilized proppant regions within a
proppant pack having permeable channels, and consolidated or
immobilized proppant regions spaced apart by open channels.
[0119] The open channels in embodiments may be formed by displacing
the STS and/or proppant in the fracture with a solids-free or
low-solids treatment fluid and a destabilizing system in such a way
that the pillar-forming proppant islands are ultimately formed by
destabilization, e.g., uneven proppant settling, and distributed in
a spaced-apart configuration within the fracture. The permeable
channels in embodiments may be formed by placing one or more
treatment fluids comprising an STS and proppant with a
destabilizing system in such a way that the proppant within the
pillar-forming proppant regions is consolidated, the pillars being
formed by destabilization and distributed in a spaced-apart
configuration within the fracture. The destabilization can occur or
begin in the preparation, mixing or pumping of the treatment
fluid(s), in the injection of the treatment fluid(s) in the
fracture, in or after the proppant placement, packing or settling
in the fracture. In embodiments, the destabilization of the STS
leads to heterogeneous proppant distribution between proppant-rich
pillar-forming islands or regions and conductive channels, which
may be open channels or permeable, proppant-filled channels as
mentioned above. In embodiments, the destabilizing system can
function in the proppant or proppant regions to consolidate or
reinforce the proppant islands and/or to strengthen the proppant
pillars. Conversely, the conductive regions can contain proppant
particles, especially relatively minor amounts, which remain
unconsolidated or do not otherwise result in obstruction or
excessive flow resistance of the channels by the proppant.
[0120] A simplified version of some embodiments of the method is
illustrated with reference to FIGS. 6-7, in which a wellbore 110
can be completed with perforations 112 in formation 114. Proppant
particles 116 and destabilizing system particles 118, either or
both of which can be formulated in one or more STS fluids, can be
injected through the wellbore 110 into a fracture 120, where they
can be heterogeneously placed in respective proppant-rich islands
122 in contact with regions 124 comprising one or more
destabilizing system components. The fracture 120 can be allowed to
close, and the proppant islands 122 compressed to form pillars to
support the fracture 120 and prevent the opposing fracture faces
from contacting each other. Simultaneously, in embodiments the
regions 124 can be open or proppant-packed. In embodiments, the
destabilizing system can facilitate consolidation and in some
further embodiments, strengthening of the regions 122. With
reference to FIG. 7, a network of interconnected conductive
channels 126 can thus be formed around the pillars 128 to provide
the fracture 120 with high conductivity for fluid flow. Fluids can
now be produced from the formation 114, into the fracture 120,
through the channels 126 and perforations 112, and into the
wellbore 110.
[0121] If desired, in some embodiments, solids in the channels 126,
or a portion of solids from the channels 126 (and/or pillars 128
where improved conductivity of the pillars is also desired), may be
removed mechanically, for example by using fluid to push solids out
of the fracture. In such instances, the solids can remain in a
solid state from the time of injection through removal from the
fracture. Alternatively or additionally in some embodiments, the
solids can be softened, dissolved, reacted or otherwise made to
degrade. Materials suitable for dissolution include for example,
and without limitation, polyvinyl alcohol (PVOH) fibers, salt, wax,
calcium carbonate, and the like and combinations thereof.
Oil-degradable solids can be selected, so that they will be
degraded by produced fluids in some embodiments. Alternatively or
additionally in embodiments, a solid can be included which is
degraded by agents purposefully placed in the formation by
injection, wherein mixing the solid with the agent induces a
delayed reaction degradation of the solid.
[0122] In some fracturing operations of the present disclosure, a
solid acid-precursor can be used as a degradable material in the
treatment fluid. Suitable acid-generating materials can include for
example, and without limitation, PLA, PGA, carboxylic acid,
lactide, glycolide, copolymers of PLA or PGA, and the like and
combinations thereof. Provided that the formation rock is
carbonate, dolomite, sandstone, or otherwise acid reactive, then
the hydrolyzed product, a reactive liquid acid, can etch the
formation at exposed surfaces. This etching can enlarge the
channels and/or remove smaller particles or gel from the
interstices between proppant particles and thus further enhance the
conductivity of the propped fracture. Other uses of the generated
acid fluid can include aiding in the breaking of residual gel,
facilitating consolidation of proppant clusters, curing or
softening resin coatings and increasing proppant permeability.
[0123] In some embodiments of the disclosure, the solids in the
treatment fluid may be formed of, or contain, a fluoride source
capable of generating hydrofluoric acid upon release of fluorine
and adequate protonation. Some nonlimiting examples of fluoride
sources which are effective for generating hydrofluoric acid
include fluoroboric acid, ammonium fluoride, ammonium fluoride, and
the like, or any mixtures thereof.
[0124] FIGS. 8-9 illustrate the acid etching process for greater
fracture conductivity. In reference to FIG. 8, proppant islands 130
are heterogeneously placed in fracture 132 with a degradable solid
acid-precursor in the regions 134. In reference to FIG. 9, delayed
hydrolysis of the acid-precursor at formation conditions forms an
acid that cuts into the face of the carbonate formation, resulting
in localized etching 136 to enlarge the channels 138. The proppant
pillars 130 remain intact to prop open the fracture.
[0125] In embodiments, the destabilizing system may be or include a
liquid-removing agent such as, for example, a compound that reacts
with or absorbs water, such as a hydratable compound or mixture of
compounds that react with water to form a hydrate, e.g., a
hydraulic cement or an inorganic cement component, such as, for
example, Portland cement, pozzolan-lime cement, slag-lime cement,
supersulfated cement, calcium aluminate cement, calcium
sulfoaluminum cement, fly ash, blast furnace slag, lime-silica
blends, lime-pozzolan blends, zeolites, cement kiln dust,
geopolymers, Sorel cements, chemically bonded phosphate ceramics,
and the like; or a superabsorbent polymer (SAP) such as crosslinked
or uncrosslinked polymers or copolymers of acrylonitrile, acrylic
acid, acrylate esters, acrylamide, vinyl alcohol, ethylene/maleic
anhydride, carboxymethylcellulose, alkylene oxide, and the like. As
used herein, a hydratable compound is a compound which forms an
inorganic salt with water bound to a metal center or incorporated
in a crystal structure. As used herein, hydraulic cement refers to
any cement that reacts with water to set. As used herein, an SAP is
one that is capable of absorbing at least ten times its weight of
water, and representative, non-limiting examples include
polyacrylamide copolymers, sodium polyacrylates, ethylene maleic
anhydride copolymers, cross-linked carboxymethylcellulose,
polyvinyl alcohol copolymers, cross-linked polyethylene oxides, and
starch grafted copolymers of polyacrylonitrile, to name a few.
[0126] The liquid-removing agents in some embodiments may be
selected to delay the liquid removal until after or just after or
mostly after the agent has been placed in the fracture or other
location where destabilization of the STS is desired. For example
in some embodiments the liquid-removing agent may be encapsulated,
e.g., in a resin, or coated, e.g., with a hydrophobic material such
as oil, for placement and activated by crushing, eroding,
dissolving or permeating the encapsulating or coating material; and
in additional or alternative embodiments the liquid removal rate
may be controlled by selecting the appropriate liquid-removal agent
and/or liquid phase media or other encapsulant, coating, or
chemical or physical trigger.
[0127] The liquid-removing agents in some embodiments may
destabilize the STS by reducing the liquid content and thereby
inducing rheological changes due to the altered SVF. For example,
in some embodiments alternating slugs of the STS may be formulated
with a hydratable compound such as hydraulic cement and/or
inorganic cement particles to cause local dehydration within the
STS placed in the fracture and create inhomogeneous fluid placement
of dispersed, high-SVF regions relative to the STS supplied to the
fracture, leading to formation of pillars comprised of hydrated
cement and other STS solids, which may be concrete-reinforced
proppant pillars in embodiments where the hydratable compound
hardens, e.g., where a hydraulic cement cures to a strong concrete.
The cement-formulated STS slugs in various embodiments may be
alternated with essentially cement-free slugs of a similar or
different STS or of an essentially solids-free fluid or low-solids
slurry. In some embodiments where the cement-free slugs comprise
STS, channels formed between the pillars may fill with a packed
solids matrix that is more conductive than the cement-containing
pillars, or in other embodiments the cement-containing pillars may
if necessary be chemically modified, e.g., by acid washing or
solvent treatment, to improve the conductivity of the
cement-containing pillars, even to the point where if desired the
conductivity of the cement-containing regions may be similar to or
exceed the conductivity of the non-cement-containing regions.
[0128] In a further example, in some embodiments the STS may be
formulated to contain SAP particles which upon placement in the
fracture or other location may absorb water through hydrogen
bonding with water molecules in the immediately surrounding areas,
dehydrating the STS and creating local inhomogeniety and
destabilization within the placed fluid resulting in conductive
channels around the water-swollen SAP materials. The water-swollen
SAP material may also in some embodiments infiltrate the
interstices between other STS particles adjacent to the SAP
particle. In some embodiments the individual SAP particles are
initially within an order of magnitude of the volume of the largest
individual STS particles, e.g., from 0.1 to 10 times the volume of
any proppant particles, but after saturation with water may
ultimately swell to a volume more than ten times the initial
volume, e.g., to from 30 to 60 times the initial volume or than the
largest STS particle, e.g., from 3 to 600 times the volume of a
proppant particle, or from 5 to 500 times the volume of a proppant
particle, or from 10 to 300 times the volume of a proppant
particle. As used herein, the initial volume of an SAP particle is
determined as it enters the wellbore, since SAP may be partially
pre-swollen during surface preparation of the treatment fluid such
as an STS containing it; for example, in some embodiments the SAP
may be prepared in an STS containing 0.9 wt % saline as the carrier
fluid wherein the SAP has an absorbency of only 50 times its
weight, and the SAP may be contacted downhole with fresh water in
which it may absorb 500 times its weight.
[0129] In embodiments, the swollen volume of the SAP particles is
less than 90% of the void volume of the proppant pack (<90%
(1-PVF)), or less than 80% of the void volume of the proppant pack
(<80% (1-PVF)), or less than 70% of the void volume of the
proppant pack (<70% (1-PVF)), or less than 60% of the void
volume of the proppant pack (<60% (1-PVF)), or less than 50% of
the void volume of the proppant pack (<50% (1-PVF)), or less
than 40% of the void volume of the proppant pack (<40% (1-PVF)),
or less than 30% of the void volume of the proppant pack (<30%
(1-PVF)), or less than 20% of the void volume of the proppant pack
(<20% (1-PVF)). In some embodiments, the swollen volume of the
SAP particles is more than 10% of the void volume of the proppant
pack (>10% (1-PVF)), or more than 20% of the void volume of the
proppant pack (>20% (1-PVF)), or more than 30% of the void
volume of the proppant pack (>30% (1-PVF)), or more than 40% of
the void volume of the proppant pack (>40% (1-PVF)), or more
than 50% of the void volume of the proppant pack (>50% (1-PVF)),
or more than 60% of the void volume of the proppant pack (>60%
(1-PVF)), or more than 70% of the void volume of the proppant pack
(>70% (1-PVF)), or more than 80% of the void volume of the
proppant pack (>80% (1-PVF)).
[0130] In some embodiments, the destabilizing system comprises a
crosslinking agent to crosslink a crosslinkable material in the
pillars. For example, the crosslinked material may destabilize the
STS, binding and consolidating the proppant and/or other solids in
the STS to form the pillars, where regions of non-crosslinked STS
or other treatment fluid remain between the pillars to form
conductive, i.e., open or permeable, flow channels between the
crosslinked regions. In some embodiments the crosslinking agent
and/or a triggering agent on the one hand, and the crosslinkable
material on the other, may be in alternated treatment fluid stages,
e.g., with different viscosities so that one stage of low viscosity
entering the fracture as an overflush will finger into another
stage previously placed in the fracture, and with crosslinking
occurring at the interface between the two fluid stages. In these
embodiments, the crosslinking occurs at least at a perimeter of the
dispersed crosslinkable material-containing regions, consolidating
the proppant-containing regions into immobilized pillars. In
embodiments, the crosslinked material reinforces at least an outer
wall of the pillar perimeters.
[0131] In embodiments, the crosslinkable material may be a suitable
monomer or polymer that is compatible in the treatment fluid, i.e.,
it forms a stable treatment slurry or does not prematurely
destabilize an STS before it can be placed in the fracture. Where
polysaccharides such as guar gum are used as the crosslinkable
material in some embodiments, the crosslinking agent may be a
source of borate or a polyvalent cation such as a metal, and the
triggering agent may be a pH control agent to modify the pH to one
conducive to crosslinking, e.g., an alkaline pH (pH>7) may be
required to initiate crosslinking. Cross-linking agents based on
boron, titanium, zirconium or aluminum complexes are typically used
to increase the effective molecular weight of the polymer for use
in high-temperature wells. The pH control agent can be selected
from amines and alkaline earth, ammonium and alkali metal salts of
sesquicarbonates, carbonates, oxalates, hydroxides, oxides,
bicarbonates, and organic carboxylates, for example, sodium
hydroxide, sodium sesquicarbonate, triethanolamine, or
tetraethylenepentamine. The crosslinkable material, the
crosslinking agent and any triggering agent may independently be
particulated solids in the slurry, dissolved in a carrier fluid
component, or a miscible or immiscible fluid in the slurry. The
composition of the STS containing the crosslinkable material, but
without the crosslinking agent and/or the triggering agent, in some
embodiments is designed such that it can be or be made relatively
more conductive than the pillars, e.g., through dilution with fluid
or other means of viscosity reduction to promote placement or
settling within the channels as opposed to the pillars.
[0132] In embodiments, depending on the desired morphology of the
pillar-channel system to be formed, the relative sizes (volumes) of
the alternated stages can be varied, e.g., from a single STS stage
followed by a single destabilizing stage, to several alternated
stages, to a train of relatively small-volume alternated
stages.
[0133] During hydraulic fracturing, high pressure pumps on the
surface inject the fracturing fluid into a wellbore adjacent to the
face or pay zone of a geologic formation. The first stage, also
referred to as the "pad stage" or the "front-end stage," involves
injecting a fracturing fluid into a borehole at a sufficiently high
flow rate and pressure sufficient to literally break or fracture a
portion of surrounding strata at the wellbore face. The pad stage
is pumped until the fracture has sufficient dimensions to
accommodate the subsequent slurry pumped in the proppant stage. The
volume of the pad can be designed by those knowledgeable in the art
of fracture design, for example, as described in Reservoir
Stimulation, 3rd Ed., M. J. Economides, K. G. Nolte, Editors, John
Wiley and Sons, New York, Chapter 10, Fracture Treatment Design, by
Jack Elbel and Larry Britt, pp. 10-1 to 10-49, 2000.
[0134] In some embodiments, e.g., the front-end stage is an STS
wherein the slurry comprises a stabilized solids mixture comprising
a particulated leakoff control system (which may include solid
and/or liquid particles, e.g., submicron particles, colloids,
micelles, PLA dispersions, latex systems, etc.) and a solids volume
fraction (SVF) of at least 0.4. In some embodiments, e.g., a pad
stage STS, the slurry comprises viscosifier in an amount to provide
a viscosity in the pad stage of greater than 300 mPa-s, determined
on a whole fluid basis at 170 s.sup.-1 and 25.degree. C.
[0135] In some embodiments, e.g., in a flush stage STS, the slurry
comprises a proppant-free slurry comprising a stabilized solids
mixture comprising a particulated leakoff control system (which may
include solid and/or liquid particles, e.g., submicron particles,
colloids, micelles, PLA dispersions, latex systems, etc.) and a
solids volume fraction (SVF) of at least 0.4. In other embodiments,
the proppant-containing fracturing stage may be used with a flush
stage comprising a first substage comprising viscosifier and a
second substage comprising slickwater. The viscosifier may be
selected from viscoelastic surfactant systems, hydratable gelling
agents (optionally including crosslinked gelling agents), and the
like. In other embodiments, the flush stage comprises an overflush
equal to or less than 3200 L (20 42-gal bbls), equal to or less
than 2400 L (15 bbls), or equal to or less than 1900 L (12
bbls).
[0136] In some embodiments, the proppant stage comprises a
continuous single injection of the STS free of spacers.
[0137] In some embodiments the STS comprises a total proppant
volume injected into the wellbore or to be injected into the
wellbore of at least 800 liters. In some embodiments, the total
proppant volume is at least 1600 liters. In some embodiments, the
total proppant volume is at least 3200 liters. In some embodiments,
the total proppant volume is at least 8000 liters. In some
embodiments, the total proppant volume is at least 80,000 liters.
In some embodiments, the total proppant volume is at least 800,000
liters. The total proppant volume injected into the wellbore or to
be injected into the wellbore is typically not more than 16 million
liters.
[0138] Sometimes it may be desirable to stop pumping a treatment
fluid during a hydraulic fracturing operation, such as for example,
when an emergency shutdown is required. For example, there may be a
complete failure of surface equipment, there may be a near wellbore
screenout, or there may be a natural disaster due to weather, fire,
earthquake, etc. However, with unstabilized fracturing fluids such
as slickwater, the proppant suspension will be inadequate at zero
pumping rate, and proppant may screen out in the wellbore and/or
fail to get placed in the fracture. With slickwater it is usually
impossible to resume the fracturing operation without first
cleaning the settled proppant out of the wellbore, often using
coiled tubing or a workover rig. There is some inefficiency in
fluidizing proppant out of the wellbore with coiled tubing, and a
significant amount of a specialized clean out fluid will be used to
entrain the proppant and lift it to surface. After the clean out, a
decision will need to be made whether to repeat the treatment or
just leave that portion of the wellbore sub-optimally treated. In
contrast, in embodiments herein, the treatment fluid is stabilized
and the operator can decide to resume and/or complete the fracture
operation, or to circulate the STS (and any proppant) out of the
well bore. By stabilizing the treatment fluid to practically
eliminate particle settling, the treatment fluid possesses the
characteristics of excellent proppant conveyance and transport even
when static.
[0139] Due to the stability of the treatment fluid in some
embodiments herein, the proppant will remain suspended and the
fluid will retain its fracturing properties during the time the
pumping is interrupted. In some embodiments herein, a method
comprises combining at least 0.36, at least 0.4, or at least 0.45 L
of proppant per liter of base fluid to form a proppant-containing
treatment fluid, stabilizing the proppant-containing treatment
fluid, pumping the STS, e.g., injecting the proppant-containing
treatment fluid into a subterranean formation and/or creating a
fracture in the subterranean formation with the treatment fluid,
stopping pumping of the STS thereby stranding the treatment fluid
in the wellbore, and thereafter resuming pumping of the treatment
fluid, e.g., to inject the stranded treatment fluid into the
formation and continue the fracture creation, and/or to circulate
the stranded treatment fluid out of the wellbore as an intact plug
with a managed interface between the stranded treatment fluid and a
displacing fluid. Circulating the treatment fluid out of the
wellbore can be achieved optionally using coiled tubing or a
workover rig, if desired, but in embodiments the treatment fluid
will itself suspend and convey all the proppant out of the wellbore
with high efficiency. In some embodiments, the method may include
managing the interface between the treatment fluid and any
displacing fluid, such as, for example, matching density and
viscosity between the treatment and displacing fluids, using a
wiper plug or pig, using a gelled pill or fiber pill or the like,
to prevent density and viscous instabilities.
[0140] In some embodiments, the treatment provides
production-related features resulting from a low water content in
the treatment fluid, such as, for example, less infiltration into
the formation and/or less water flowback. Formation damage occurs
whenever the native reservoir conditions are disturbed. A
significant source of formation damage during hydraulic fracturing
occurs when the fracturing fluids contact and infiltrate the
formation. Measures can be taken to reduce the potential for
formation damage, including adding salts to improve the stability
of fines and clays in the formation, addition of scale inhibitors
to limit the precipitation of mineral scales caused by mixing of
incompatible brines, addition of surfactants to minimize capillary
blocking of the tight pores and so forth. There are some types of
formation damage for which additives are not yet available to
solve. For example, some formations will be mechanically weakened
upon coming in contact with water, referred to herein as
water-sensitive formations. Thus, it is desirable to significantly
reduce the amount of water that can infiltrate the formation during
a well completion operation.
[0141] Very low water slurries and water free slurries according to
certain embodiments disclosed herein offer a pathway to
significantly reduce water infiltration and the collateral
formation damage that may occur. Low water STS minimizes water
infiltration relative to slick water fracture treatments by two
mechanisms. First, the water content in the STS can be less than
about 40% of slickwater per volume of respective treatment fluid,
and the STS can provide in some embodiments more than a 90%
reduction in the amount of water used per volume or weight of
proppant placed in the formation. Second, the solids pack in the
STS in embodiments including subproppant particles retains more
water than conventional proppant packs so that less water is
released from the STS into the formation.
[0142] After fracturing, water flowback plagues the prior art
fracturing operations. Load water recovery typically characterizes
the initial phase of well start up following a completion
operation. In the case of horizontal wells with massive hydraulic
fractures in unconventional reservoirs, 15 to 30% of the injected
hydraulic fracturing fluid is recovered during this start up phase.
At some point, the load water recovery rate becomes very low and
the produced gas rate high enough for the well to be directed to a
gas pipeline to market. We refer to this period of time during load
water recovery as the fracture clean up phase. It is normal for a
well to clean up for several days before being connected to a gas
sales pipeline. The flowback water must be treated and/or disposed
of, and delays pipeline production. A low water content slurry
according to embodiments herein can significantly reduce the volume
and/or duration, or even eliminate this fracture clean up phase.
Fracturing fluids normally are lost into the formation by various
mechanisms including filtration into the matrix, imbibition into
the matrix, wetting the freshly exposed new fracture face, loss
into natural fractures. A low water content slurry will become dry
with only a small loss of its water into the formation by these
mechanisms, leaving in some embodiments no or very little free
water to be required (or able) to flow back during the fracture
clean up stage. The advantages of zero or reduced flowback include
reduced operational cost to manage flowback fluid volumes, reduced
water treatment cost, reduced time to put well to gas sales,
reduction of problematic waste that will develop by injected waters
solubilizing metals, naturally occurring radioactive materials,
etc.
[0143] There have also been concerns expressed by the general
public that hydraulic fracturing fluid may find some pathway into a
potable aquifer and contaminate it. Although proper well
engineering and completion design, and fracture treatment execution
will prevent any such contamination from occurring, if it were to
happen by an unforeseen accident, a slickwater system will have
enough water and mobility in an aquifer to migrate similar to a
salt water plume. A low water STS in embodiments may have a 90%
reduction in available water per mass of proppant such that any
contact with an aquifer, should it occur, will have much less
impact than slickwater treatment.
[0144] Subterranean formations are heterogeneous, with layers of
high, medium, and low permeability strata interlaced. A hydraulic
fracture that grows to the extent that it encounters a high
permeability zone will suddenly experience a high leakoff area that
will attract a disproportionately large fraction of the injected
fluid significantly changing the geometry of the created hydraulic
fracture possibly in an undesirable manner. A hydraulic fracturing
fluid that would automatically plug a high leakoff zone is useful
in that it would make the fracture execution phase more reliable
and probably ensure the fracture geometry more closely resembles
the designed geometry (and thus production will be closer to that
expected). One feature of embodiments of an STS is that it will
dehydrate and become an immobile mass (plug) upon losing more than
25% of the water it is formulated with. As an STS in embodiments
only contains up to 50% water by volume, then it will only require
a loss of a total of 12.5% of the STS treatment fluid volume in the
high fluid loss affected area to become an immobile plug and
prevent subsequent fluid loss from that area; or in other
embodiments only contains up to 40% water by volume, requiring a
loss of a total of 10% of the STS treatment fluid volume to become
immobile. A slick water system would need to lose around 90% or 95%
of its total volume to dehydrate the proppant into an immobile
mass.
[0145] Sometimes, during a hydraulic fracture treatment, the
surface treating pressure will approach the maximum pressure limit
for safe operation. The maximum pressure limit may be due to the
safe pressure limitation of the wellhead, the surface treating
lines, the casing, or some combination of these items. One common
response to reaching an upper pressure limit is to reduce the
pumping rate. However, with ordinary fracturing fluids, the
proppant suspension will be inadequate at low pumping rates, and
proppant may fail to get placed in the fracture. The stabilized
fluids in some embodiments of this disclosure, which can be highly
stabilized and practically eliminate particle settling, possess the
characteristic of excellent proppant conveyance and transport even
when static. Thus, some risk of treatment failure is mitigated
since a fracture treatment can be pumped to completion in some
embodiments herein, even at very low pump rates should injection
rate reduction be necessary to stay below the maximum safe
operating pressure during a fracture treatment with the stabilized
treatment fluid.
[0146] In some embodiments, the injection of the treatment fluid of
the current application can be stopped all together (i.e. at an
injection rate of 0 bbl/min). Due to the excellent stability of the
treatment fluid, very little or no proppant settling occurs during
the period of 0 bbl/min injection. Well intervention, treatment
monitoring, equipment adjustment, etc. can be carried out by the
operator during this period of time. The pumping can be resumed
thereafter. Accordingly, in some embodiments of the current
application, there is provided a method comprising injecting a
proppant laden treatment fluid into a subterranean formation
penetrated by a wellbore, initiating or propagating a fracture in
the subterranean formation with the treatment fluid, stopping
injecting the treatment fluid for a period of time, restarting
injecting the treatment fluid to continue the initiating or
propagating of the fracture in the subterranean formation.
[0147] In some embodiments, the treatment and system may achieve
the ability to fracture using a carbon dioxide proppant stage
treatment fluid. Carbon dioxide is normally too light and too thin
(low viscosity) to carry proppant in a slurry useful in fracturing
operations. However, in an STS fluid, carbon dioxide may be useful
in the liquid phase, especially where the proppant stage treatment
fluid also comprises a particulated fluid loss control agent. In
embodiments, the liquid phase comprises at least 10 wt % carbon
dioxide, at least 50 wt % carbon dioxide, at least 60 wt % carbon
dioxide, at least 70 wt % carbon dioxide, at least 80 wt % carbon
dioxide, at least 90 wt % carbon dioxide, or at least 95 wt %
carbon dioxide. The carbon dioxide-containing liquid phase may
alternatively or additionally be present in any pre-pad stage, pad
stage, front-end stage, flush stage, post-flush stage, or any
combination thereof.
[0148] Zonal isolations operations in embodiments are improved by
specific STS formulations optimized for leakoff control and/or
bridging abilities. Relatively small quantities of the STS
radically improve the sealing ability of mechanical and inflatable
packers by filling and bridging off gaps. Permanent isolation of
zones is achieved in some embodiments by bullheading low
permeability versions of the STS into water producing formations or
other formations desired to be isolated. Isolation in some
embodiments is improved by using a setting formulation of the STS,
but non-setting formulations can provide very effective permanent
isolation. Temporary isolation may be delivered in embodiments by
using degradable materials to convert a non-permeable pack into a
permeable pack after a period of time.
[0149] The pressure containing ability and ease of
placement/removal of sand plugs in embodiments are significantly
improved using appropriate STS formulations selected for high
bridging capacity. Such formulations will allow much larger gaps
between the sand packer tool and the well bore for the same
pressure capability. Another major advantage is the reversibility
of dehydration in some embodiments; a solid sand pack may be
readily re-fluidized and circulated out, unlike conventional sand
plugs.
[0150] In other embodiments, plug and abandon work may be improved
using CRETE cementing formulations in the STS and also by placing
bridging/leakoff controlling STS formulations below and/or above
cement plugs to provide a seal repairing material. CRETE cementing
formulations are disclosed in U.S. Pat. No. 6,626,991, GB
2,277,927, U.S. Pat. No. 6,874,578, WO 2009/046980, Schlumberger
CemCRETE Brochure (2003), and Schlumberger Cementing Services and
Products--Materials, pp. 39-76 (2012), available at
http://www.slb.com/.about./media/Files/cementing/catalogs/05_cementing_ma-
terials.pdf which are hereby incorporated herein by reference. The
ability of the STS to re-fluidize after long periods of
immobilization facilitates this embodiment.
[0151] Accordingly, the present disclosure provides the following
Embodiments: [0152] A. A method of placing a proppant pack into a
fracture formed in a subterranean formation, the method comprising:
injecting a well treatment fluid through a wellbore into a fracture
in a subterranean formation, wherein at least a portion of the well
treatment fluid comprises a proppant-containing stage, wherein at
least a portion of the well treatment fluid comprises a stabilized
slurry stage and wherein the proppant-containing and stabilized
slurry portions may be the same or different; injecting a
destabilizing system into the fracture with the well treatment
fluid to destabilize the slurry stage and form regions of
consolidated proppant from the destabilized slurry stage; and
placing a plurality of proppant clusters forming pillars from the
consolidated proppant regions spaced apart by fluid flow channels
(which may be open or relatively permeable) from the formation
through the fracture toward the wellbore. [0153] B. The method of
Embodiment A wherein the stabilized slurry comprises a liquid phase
(which may optionally be aqueous and/or hydrophobic), and wherein
the slurry destabilizing system comprises a liquid-removing agent
to remove fluid from the slurry (e.g., and thereby increase the
solids volume fraction (SVF) of the slurry). [0154] C. The method
of Embodiment B wherein the liquid phase comprises water (which may
optionally be in a continuous or dispersed aqueous phase in an
emulsion with a hydrophobic phase) and the liquid-removal agent
comprises a hydratable compound (e.g., a hydraulic cement or an
inorganic cement component, such as, for example, Portland cement,
pozzolan-lime cement, slag-lime cement, supersulfated cement,
calcium aluminate cement, calcium sulfoaluminum cement, fly ash,
blast furnace slag, lime-silica blends, lime-pozzolan blends,
zeolites, cement kiln dust, geopolymers, Sorel cements, chemically
bonded phosphate ceramics). [0155] D. The method of Embodiment B or
Embodiment C wherein the liquid phase comprises water (which may
optionally be in a continuous or dispersed aqueous phase in an
emulsion with a hydrophobic phase) and the liquid-removal agent
comprises a superabsorbent polymer. [0156] E. The method of any one
of Embodiments A to D, further comprising: sequentially injecting a
first stage of the treatment fluid into the formation followed by a
second stage of the treatment fluid (e.g., as an overflush),
wherein the first and second stages have different viscosities,
different specific gravities, or both, to initiate viscous
fingering; wherein the stabilized slurry comprises the proppant in
the first stage; wherein the destabilizing system comprises a
crosslinkable material in the first stage, and a crosslinking agent
in at least one of the first and second stages to crosslink the
crosslinkable material in the pillars. [0157] F. The method of
Embodiment E wherein the specific gravity of the first stage is
matched with the specific gravity of the second stage to mitigate
gravity effects (or where the difference in density between two
fluids is less than 0.9 g/mL, or less than 0.8 g/L, or less than
0.7 g/L, or less than 0.6 g/L, or less than 0.5 g/L, or less than
0.4 g/L, or less than 0.3 g/L, or less than 0.2 g/L, or less than
0.1 g/L, or less than 0.05 g/L). [0158] G. The method of Embodiment
E or Embodiment F wherein the crosslinkable material comprises a
polysaccharide, and wherein the crosslinking agent comprises a
source of borate or a polyvalent metal. [0159] H. The method of
Embodiment G wherein one of the first and second stages comprises a
pH control material to provide an alkaline pH and the other one of
the first and second stages comprises the source of borate or
polyvalent metal. [0160] I. The method of Embodiment H wherein the
first stage comprises the polysaccharide and the pH control agent
and the second stage comprises the source of borate or polyvalent
metal. [0161] J. The method of Embodiment H wherein the first stage
comprises the polysaccharide and the source of borate or polyvalent
metal and the second stage comprises the pH control agent. [0162]
K. The method of Embodiment H wherein the first stage comprises
subproppant particles, has a slurry solids volume fraction (SVF) of
0.6 or more and solids comprising a packed volume fraction (PVF) of
0.7 or more; and wherein the second stage is free of solids or has
an SVF less than 0.05. [0163] L. The method of Embodiment A,
further comprising: alternatingly injecting a plurality of pulsed
first and second slugs of the well treatment fluid, wherein the
first and second slugs each comprise a said stabilized slurry which
may be the same or different; wherein the slurry destabilizing
system comprises a reagent selectively present in one of the first
and second slugs to respectively form the pillars from consolidated
proppant packs and the channels from relatively permeable proppant
packs. [0164] M. The method of Embodiment L wherein the first and
second slugs comprise a crosslinkable material and wherein the
reagent comprises a solid particulated crosslinking agent. [0165]
N. The method of Embodiment L or Embodiment M wherein the
stabilized slurries comprise a liquid phase, and wherein the
reagent comprises a solid liquid-removal agent to remove fluid from
at least one of the slurries. [0166] O. The method of Embodiment N
wherein the liquid phase comprises water (which may optionally be
in a continuous or dispersed aqueous phase in an emulsion with a
hydrophobic phase) and the reagent comprises a hydratable compound
(e.g., a hydraulic cement or an inorganic cement component, such
as, for example, Portland cement, pozzolan-lime cement, slag-lime
cement, supersulfated cement, calcium aluminate cement, calcium
sulfoaluminum cement, fly ash, blast furnace slag, lime-silica
blends, lime-pozzolan blends, zeolites, cement kiln dust,
geopolymers, Sorel cements, chemically bonded phosphate ceramics).
[0167] P. The method of Embodiment N wherein the liquid phase
comprises water (which may optionally be in a continuous or
dispersed aqueous phase in an emulsion with a hydrophobic phase)
and the reagent comprises a superabsorbent polymer. [0168] Q. The
method of any one of Embodiments A to P, further comprising
stabilizing the well treatment fluid to form the stabilized slurry.
[0169] R. The method of Embodiment Q wherein the stabilized slurry
is formed by at least one of the slurry stabilization operations
selected from: (1) introducing sufficient particles into the slurry
to increase a solids volume fraction (SVF) of the slurry fluid to
at least 0.4; (2) increasing a low-shear viscosity of the slurry to
at least 1 Pa-s (5.11 s.sup.-1, 25.degree. C.); (3) increasing a
yield stress of the slurry to at least 1 Pa; (4) increasing
apparent viscosity of the slurry to at least 50 mPa-s (170
s.sup.-1, 25.degree. C.); (5) introducing a multimodal solids phase
into the slurry; (6) introducing a solids phase having a packed
volume fraction (PVF) greater than 0.7 into the slurry; (7)
introducing into the slurry a viscosifier selected from
viscoelastic surfactants and hydratable gelling agents; (8)
introducing colloidal particles into the slurry; (9) reducing a
particle-fluid density delta in the slurry to less than 1.6 g/mL;
(10) introducing particles into the slurry having an aspect ratio
of at least 6; (11) introducing ciliated or coated proppant into
the slurry; and (12) combinations thereof. [0170] S. The method of
Embodiment Q wherein the stabilized slurry is formed by at least
two of the slurry stabilization operations selected from: (1)
introducing sufficient particles into the slurry to increase a
solids volume fraction (SVF) of the slurry fluid to at least 0.4;
(2) increasing a low-shear viscosity of the slurry to at least 1
Pa-s (5.11 s.sup.-1, 25.degree. C.); (3) increasing a yield stress
of the slurry to at least 1 Pa; (4) increasing apparent viscosity
of the slurry to at least 50 mPa-s (170 s.sup.-1, 25.degree. C.);
(5) introducing a multimodal solids phase into the slurry; (6)
introducing a solids phase having a packed volume fraction (PVF)
greater than 0.7 into the slurry; (7) introducing into the slurry a
viscosifier selected from viscoelastic surfactants and hydratable
gelling agents; (8) introducing colloidal particles into the
slurry; (9) reducing a particle-fluid density delta in the slurry
to less than 1.6 g/mL; (10) introducing particles into the slurry
having an aspect ratio of at least 6; (11) introducing ciliated or
coated proppant into the slurry; and (12) combinations thereof.
[0171] T. The method of Embodiment Q wherein the stabilized slurry
is formed by at least three of the slurry stabilization operations
selected from: (1) introducing sufficient particles into the slurry
to increase a solids volume fraction (SVF) of the slurry fluid to
at least 0.4; (2) increasing a low-shear viscosity of the slurry to
at least 1 Pa-s (5.11 s.sup.-1, 25.degree. C.); (3) increasing a
yield stress of the slurry to at least 1 Pa; (4) increasing
apparent viscosity of the slurry to at least 50 mPa-s (170
s.sup.-1, 25.degree. C.); (5) introducing a multimodal solids phase
into the slurry; (6) introducing a solids phase having a packed
volume fraction (PVF) greater than 0.7 into the slurry; (7)
introducing into the slurry a viscosifier selected from
viscoelastic surfactants and hydratable gelling agents; (8)
introducing colloidal particles into the slurry; (9) reducing a
particle-fluid density delta in the slurry to less than 1.6 g/mL;
(10) introducing particles into the slurry having an aspect ratio
of at least 6; (11) introducing ciliated or coated proppant into
the slurry; and (12) combinations thereof. [0172] U. The method of
Embodiment Q wherein the stabilized slurry is formed by at least
four of the slurry stabilization operations selected from: (1)
introducing sufficient particles into the slurry to increase a
solids volume fraction (SVF) of the slurry fluid to at least 0.4;
(2) increasing a low-shear viscosity of the slurry to at least 1
Pa-s (5.11 s.sup.-1, 25.degree. C.); (3) increasing a yield stress
of the slurry to at least 1 Pa; (4) increasing apparent viscosity
of the slurry to at least 50 mPa-s (170 s.sup.-1, 25.degree. C.);
(5) introducing a multimodal solids phase into the slurry; (6)
introducing a solids phase having a packed volume fraction (PVF)
greater than 0.7 into the slurry; (7) introducing into the slurry a
viscosifier selected from viscoelastic surfactants and hydratable
gelling agents; (8) introducing colloidal particles into the
slurry; (9) reducing a particle-fluid density delta in the slurry
to less than 1.6 g/mL; (10) introducing particles into the slurry
having an aspect ratio of at least 6; (11) introducing ciliated or
coated proppant into the slurry; and (12) combinations thereof.
[0173] V. The method of Embodiment Q wherein the stabilized slurry
is formed by at least five of the slurry stabilization operations
selected from: (1) introducing sufficient particles into the slurry
to increase a solids volume fraction (SVF) of the slurry fluid to
at least 0.4; (2) increasing a low-shear viscosity of the slurry to
at least 1 Pa-s (5.11 s.sup.-1, 25.degree. C.); (3) increasing a
yield stress of the slurry to at least 1 Pa; (4) increasing
apparent viscosity of the slurry to at least 50 mPa-s (170
s.sup.-1, 25.degree. C.); (5) introducing a multimodal solids phase
into the slurry; (6) introducing a solids phase having a packed
volume fraction (PVF) greater than 0.7 into the slurry; (7)
introducing into the slurry a viscosifier selected from
viscoelastic surfactants and hydratable gelling agents; (8)
introducing colloidal particles into the slurry; (9) reducing a
particle-fluid density delta in the slurry to less than 1.6 g/mL;
(10) introducing particles into the slurry having an aspect ratio
of at least 6; (11) introducing ciliated or coated proppant into
the slurry; and (12) combinations thereof. [0174] W. The method of
any one of Embodiments R to V comprising introducing sufficient
particles into the slurry to increase the SVF to at least 0.4 (or
0.5 or more, or 0.6 or more, or 0.56 to 0.61). [0175] X. The method
of any one of Embodiments R to W comprising increasing the
low-shear viscosity of the slurry to at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.). [0176] Y. The method of any one of
Embodiments R to X comprising increasing the yield stress of the
treatment fluid to at least 1 Pa (or to from 1 to 20 Pa). [0177] Z.
The method of any one of Embodiments A to Y wherein the stabilized
slurry comprises solids comprising 60-75 volume percent proppant
larger than 100 mesh, 5-20 volume percent 100 mesh sand, 5-20
volume percent silica flour, and 8-30 volume percent of 1-10 micron
particles, based on the total volume of solids in the stabilized
slurry, and from 1.2 to 4.8 g/L (10-40 ppt) of a hydratable gelling
agent. [0178] AA. A propped fracture system obtained as a result of
placing the proppant pack into the fracture according to the method
of any one of Embodiments A to Z. [0179] BB. A system for
fracturing a subterranean formation, comprising: a supply module to
inject a well treatment fluid through a wellbore into a fracture in
a subterranean formation, wherein at least a portion of the well
treatment fluid comprises a proppant-containing stage fluid,
wherein at least a portion of the well treatment fluid comprises a
stabilized slurry stage fluid and wherein the proppant-containing
and stabilized slurry portions may be the same or different fluids;
and a destabilizing system in communication with the supply module
for injection into the fracture with the well treatment fluid to
destabilize the slurry stage fluid, form regions of consolidated
proppant from the destabilized slurry stage fluid and form pillars
spaced apart by fluid flow channels (which may be open or
permeable) from the formation through the fracture toward the
wellbore. [0180] CC. The system of Embodiment BB wherein the
stabilized slurry comprises a liquid phase (which may optionally be
aqueous and/or hydrophobic), and wherein the slurry destabilizing
system comprises a liquid-removing agent to remove fluid from the
stabilized slurry (e.g., and thereby increase the solids volume
fraction (SVF) of the slurry). [0181] DD. The system of Embodiment
CC wherein the liquid phase comprises water (which may optionally
be in a continuous or dispersed aqueous phase in an emulsion with a
hydrophobic phase) and the liquid-removal agent comprises a
hydratable compound (e.g., a hydraulic cement or an inorganic
cement component, such as, for example, Portland cement,
pozzolan-lime cement, slag-lime cement, supersulfated cement,
calcium aluminate cement, calcium sulfoaluminum cement, fly ash,
blast furnace slag, lime-silica blends, lime-pozzolan blends,
zeolites, cement kiln dust, geopolymers, Sorel cements, chemically
bonded phosphate ceramics). [0182] EE. The system of Embodiment CC
or Embodiment DD wherein the liquid phase comprises water (which
may optionally be in a continuous or dispersed aqueous phase in an
emulsion with a hydrophobic phase) and the liquid-removal agent
comprises a superabsorbent polymer.
[0183] FF. The system of any one of Embodiments BB to EE, further
comprising: a pump system to sequentially inject a first stage of
the treatment fluid into the formation followed by a second stage
of the treatment fluid (e.g., as an overflush), wherein the first
and second stages have different viscosities, different specific
gravities, or both, to initiate viscous fingering; wherein the
stabilized slurry comprises the proppant in the first stage;
wherein the destabilizing system comprises a crosslinkable material
in the first stage, and a crosslinking agent in at least one of the
first and second stages to crosslink the crosslinkable material in
the pillars. [0184] GG. The system of Embodiment FF wherein the
specific gravity of the first stage is matched with the specific
gravity of the second stage to mitigate gravity effects (or where
the difference in density between two fluids is less than 0.9 g/mL,
or less than 0.8 g/L, or less than 0.7 g/L, or less than 0.6 g/L,
or less than 0.5 g/L, or less than 0.4 g/L, or less than 0.3 g/L,
or less than 0.2 g/L, or less than 0.1 g/L, or less than 0.05 g/L).
[0185] HH. The system of Embodiment GG wherein the crosslinkable
material comprises a polysaccharide, and wherein the crosslinking
agent comprises a source of borate or a polyvalent metal. [0186]
II. The system of Embodiment HH wherein one of the first and second
stages comprises a pH control material to provide an alkaline pH
and the other one of the first and second stages comprises the
source of borate or polyvalent metal. [0187] JJ. The system of
Embodiment II wherein the first stage comprises the polysaccharide
and the pH control agent and the second stage fluid comprises the
source of borate or polyvalent metal. [0188] KK. The system of
Embodiment II wherein the first stage comprises the polysaccharide
and the source of borate or polyvalent metal and the second stage
comprises the pH control agent. [0189] LL. The system of Embodiment
II wherein the stabilized slurry comprises the proppant and
subproppant particles, has a solids volume fraction (SVF) of 0.6 or
more and solids comprising a packed volume fraction (PVF) of 0.7 or
more; and wherein the second stage is free of solids or has an SVF
less than 0.05. [0190] MM. The system of Embodiment BB, further
comprising: a pump system to alternatingly inject a plurality of
pulsed first and second slugs of the treatment fluid, wherein the
first and second slugs each comprise a said stabilized slurry;
wherein the slurry destabilizing system comprises a reagent
selectively present in one of the first and second slugs to
respectively form the pillars from consolidated proppant packs and
the channels from relatively permeable proppant packs. [0191] NN.
The system of Embodiment MM wherein the first and second slugs
comprise a crosslinkable material and wherein the reagent comprises
a solid particulated crosslinking agent. [0192] OO. The system of
Embodiment MM or Embodiment NN wherein the stabilized slurries
comprise a liquid phase, and wherein the reagent comprises a solid
liquid-removal agent to remove fluid from the stabilized slurry.
[0193] PP. The system of Embodiment NN wherein the liquid phase
comprises water (which may optionally be in a continuous or
dispersed aqueous phase in an emulsion with a hydrophobic phase)
and the reagent comprises a hydratable compound (e.g., a hydraulic
cement or an inorganic cement component, such as, for example,
Portland cement, pozzolan-lime cement, slag-lime cement,
supersulfated cement, calcium aluminate cement, calcium
sulfoaluminum cement, fly ash, blast furnace slag, lime-silica
blends, lime-pozzolan blends, zeolites, cement kiln dust,
geopolymers, Sorel cements, chemically bonded phosphate ceramics).
[0194] QQ. The system of Embodiment NN wherein the liquid phase
comprises water (which may optionally be in a continuous or
dispersed aqueous phase in an emulsion with a hydrophobic phase)
and the reagent comprises a superabsorbent polymer. [0195] RR. The
system of any one of Embodiments BB to QQ wherein the stabilized
slurry the stabilized slurry comprises at least one of the
stability indicia selected from: (1) a solids volume fraction (SVF)
of at least 0.4; (2) a low-shear viscosity of at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.); (3) a yield stress of at least 1 Pa; (4)
an apparent viscosity of at least 50 mPa-s (170 s.sup.-1,
25.degree. C.); (5) a multimodal solids phase; (6) a solids phase
having a packed volume fraction (PVF) greater than 0.7; (7) a
viscosifier selected from viscoelastic surfactants, in an amount
ranging from 0.01 up to 7.2 g/L (60 ppt), and hydratable gelling
agents in an amount ranging from 0.01 up to 4.8 g/L (40 ppt), based
on the volume of fluid phase; (8) colloidal particles; (9) a
particle-fluid density delta less than 1.6 g/mL; (10) particles
having an aspect ratio of at least 6; (11) ciliated or coated
proppant; and (12) combinations thereof. [0196] SS. The system of
Embodiment RR wherein the SVF is at least 0.4 (or 0.5 or more, or
0.6 or more, or 0.56 to 0.61). [0197] TT. The system of any one of
Embodiments RR to SS wherein the low-shear viscosity of the slurry
is at least 1 Pa-s (5.11 s.sup.-1, 25.degree. C.). [0198] UU. The
system of any one of Embodiments RR to TT wherein the yield stress
is at least 1 Pa (or to from 1 to 20 Pa). [0199] VV. The system of
any one of Embodiments RR to UU wherein the apparent viscosity is
at least 50 mPa-s (170 s.sup.-1, 25.degree. C.). [0200] WW. The
system of any one of Embodiments RR to VV comprising the multimodal
solids phase. [0201] XX. The system of any one of Embodiments RR to
WW, comprising the packed volume fraction (PVF) greater than 0.7.
[0202] YY. The system of any one of Embodiments RR to XX,
comprising the viscoelastic surfactant in an amount ranging from
0.01 up to 7.2 g/L (60 ppt) based on the volume of fluid phase.
[0203] ZZ. The system of any one of Embodiments RR to YY comprising
the hydratable gelling agent in an amount ranging from 0.01 up to
4.8 g/L (40 ppt) based on the volume of fluid phase.
EXAMPLES
Example 1
[0204] Stabilized Treatment Slurry. An example of a stabilized
treatment slurry (STS) is provided in Table 1 below.
TABLE-US-00001 TABLE 1 STS Composition. Stabilized Proppant Free
Stabilized Proppant/Solids Fluid components Slurry (g/L of STS)
Slurry (g/L of STS) Crystalline silica 0 900-1100 40/70 mesh
Crystalline silica 0 125-225 100 mesh Crystalline silica 600-800
100-250 400 mesh Calcium Carbonate.sup.1 300-400 175-275 2 micron
Water 150-250 150-250 Latex.sup.2 300-500 100-300 Dispersant.sup.3
2-4 2-4 Antifoam4 3-5 1-3 Viscosifier.sup.5 6-10 6-10 .sup.1Calcium
Carbonate = SAFECARB 2 from MI-SWACO .sup.2Latex =
Styrene-Butadiene copolymer dispersion .sup.3Dispersant =
Polynaphthalene sulfonate .sup.4Antifoam = Silicone emulsion
.sup.5Viscosifier = AMPS/acrylamide copolymer solution
[0205] Excellent particle (proppant) suspension capability and very
low fluid loss were observed. The fluid leakoff coefficient was
determined by following the static fluid loss test and procedures
set forth in Section 8-8.1, "Fluid loss under static conditions,"
in Reservoir Stimulation, 3.sup.rd Edition, Schlumberger, John
Wiley & Sons, Ltd., pp. 8-23 to 8-24, 2000, in a filter-press
cell using ceramic disks (FANN filter disks, part number 210538)
saturated with 2% KCl solution and covered with filter paper, and
test conditions of ambient temperature (25.degree. C.), a
differential pressure of 3.45 MPs (500 psi), 100 ml sample loading,
and a loss collection period of 60 minutes, or an equivalent test.
The results are shown in FIG. 3. The total leakoff coefficient of
STS was determined to be very low from the test. The STS fluid loss
did not appear to be a function of differential pressure. This
unique low to no fluid loss property, and excellent stability (low
rate of solids settling), allows the STS to be pumped at a low rate
without concern of screen out.
Example 2
[0206] Stabilized Treatment Slurry. Another example of an STS is
provided in Table 2 below, which has an SVF of 60%. The fluid is
very flowable and has been pumped into a subterranean formation
with available field equipment. Typical slickwater operation has an
SVF up to about 8% only. In contrast, the fluid in the current
example delivers proppant at a much higher efficiency. It should be
noted that not all of the solids in these embodiments are
conventional proppant, and the 40/70 mesh proppant and 100 mesh
sand are conventionally referred to as proppant. In this regard,
the SVF of the conventional proppant in the total fluid is 44.2%,
and the volumetric ratio of proppant to fluid phase is quite high,
44.2/39.9=1.11. This represents a breakthrough in water efficiency
for proppant placement.
TABLE-US-00002 TABLE 2 STS Composition Components Wt % Vol % 40/70
proppant 49.7% 37.5% 100 mesh sand 8.9% 6.7% 30.mu. silica 8.9%
6.7% 2.mu. CaCO3 12.4% 9.2% Liquid Latex 9.8% 19.3% Water and
additives 10.3% 20.6%
[0207] A low total water content in the STS results from both high
proppant loading in the STS and the conversely relatively low
amount of free water required for the slurry to be
flowable/pumpable. Low water volume injection embodiments certainly
result in correspondingly low fluid volumes to flow back. It can
also be seen from the STS example in Table 2, the PVF of that
formulation is 69%. This means that only 31% of the volume is
fluid-filled voids. In a solid pack, a certain amount of water is
retained due to capillary and/or surface wetting effects. The
amount of retained water in this embodiment is higher than that of
a conventional proppant pack, further reducing the amount of water
flow back (in addition to inhibiting water infiltration into the
matrix). Considering the statistical amount of water flowed back
from a shale, carbonate or siltstone formation after a conventional
fracturing treatment, in embodiments of the STS fracturing
treatment the flow back is less than 30% or less than 20% or less
than 10% of the water injected in the STS stage and/or the total
water injected (including any pre-pad, pad, front-end, proppant,
flush, and post-flush stage(s)), and there is a good chance that
there may even be zero flow back.
[0208] As can be seen, to transport the same amount of proppant,
the amount of water required is significantly reduced. To deliver
45,000 kg (100,000 lb) of proppant, a conventional slickwater
treatment will require the use of 380 m.sup.3 (100,000 gallons) of
water assuming the average slickwater proppant concentration is
0.12 kg/L (1 ppa). On the contrary, to deliver the same amount of
proppant using the STS formulation of these embodiments, less than
11.3 m.sup.3 (3,000 gallons) of water are required, for a proppant
stage placement v/v efficiency of 150 percent (volume of proppant
placed is 1.5 times volume of water in proppant stage) versus 4.5
percent for the 1 ppa slickwater. The STS in this embodiment is
using only 3% of the water that is required using the slickwater
fracturing technique. Even considering any requirements of a pad, a
flush and other non-STS fluid, the amount of water used by STS in
this embodiment is still at least an order of magnitude less than
the comparable slickwater technique, e.g., less than 10% of the
water required for the slickwater technique. In embodiments, the
proppant stage placement v/v water efficiency (volume of
proppant/volume of water) is at least 10%, at least 20%, at least
30%, at least 40%, at least 50%, at least 60%, at least 70%, at
least 80%, at least 90%, at least 100%, at least 110%, or at least
120%, and in additional or alternative embodiments the aqueous
phase in the high-efficiency proppant stage has a viscosity less
than 300 mPa-s.
Example 3
[0209] STS Slurry Stability Tests. A slurry sample was prepared
with the formulation given in Table 3.
TABLE-US-00003 TABLE 3 STS Composition Components g/L Slurry 40/70
proppant 700-800 100 mesh sand 100-150 30.mu. silica 100-140 2.mu.
CaCO3 (SafeCARB2) 150-200 0.036 wt % Diutan solution 0.4-0.6 Water
and other additives 250-350
[0210] The slurry was prepared by mixing the water, diutan and
other additives, and SafeCARB particles in two 37.9-L (10 gallon)
batches, one in an eductor and one in a RUSHTON turbine, the two
batches were combined in a mortar mixer and mixed for one minute.
Then the sand was added and mixed one minute, silica added and
mixed with all components for one minute. A sample of the freshly
prepared slurry was evaluated in a Fann 35 rheometer at 25.degree.
C. with an R1B5F1 configuration at the beginning of the test with
speed ramped up to 300 rpm and back down to 0, an average of the
two readings at 3, 6, 100, 200 and 300 rpm (2.55, 5.11, 85.0, 170
and 255 s.sup.-1) recorded as the shear stress, and the yield
stress (.tau..sub.0) determined as the y-intercept using the
Herschel-Buckley rheological model.
[0211] The slurry was then placed and sealed with plastic in a 152
mm (6 in.) diameter vertical gravitational settling column filled
with the slurry to a depth of 2.13 m (7 ft). The column was
provided with 25.4-mm (1 in.) sampling ports located on the
settling column at 190 mm (6'3''), 140 mm (4'7''), 84 mm (2'9'')
and 33 mm (1'1'') connected to clamped tubing. The settling column
was mounted with a shaker on a platform isolated with four airbag
supports. The shaker was a BUTTKICKER brand low frequency audio
transducer. The column was vibrated at 15 Hz with a 1 mm amplitude
(vertical displacement) for two 4-hour periods the first and second
settling days, and thereafter maintained in a static condition for
10 days (12 days total settling time, hereinafter "8 h@ 15 Hz/10 d
static"). The 15 Hz/1 mm amplitude condition was selected to
correspond to surface transportation and/or storage conditions
prior to the well treatment.
[0212] At the end of the settling period the depth of any free
water at the top of the column was measured, and samples were
obtained, in order from the top sampling port down to the bottom.
The post-settling period samples were similarly evaluated in the
rheometer under the same configuration and conditions as the
initial slurry, and the Herschel-Buckley yield stress calculated.
The results are presented in Table 4.
TABLE-US-00004 TABLE 4 Rheological properties, initial and 8 h @ 15
Hz/10 d Dynamic-static aged samples Shear Stress (Pa (lbf/100 ft2))
Delta, @ Shear Rate (s.sup.-1): 2.55 5.1 85 170 170 s.sup.-1 (%)
Initial slurry 17.9 21.3 84.5 135 (base line) (37.4) (44.5) (176.4)
(282.7) Aged slurry, 8 h @ 15 Hz/10 d static Top sample 15.4 19.3
76.8 123 -8.9 (32.1) (40.4) (160.3) (257.1) Upper middle sample
15.9 20.2 81.9 132 -2.3 (33.3) (42.2) (171) (276.1) Lower middle
sample 14.8 19.3 79.3 130 -3.7 (30.9) (40.4) (165.7) (271.4) Bottom
sample 18.6 22.7 89.6 146 +8.1 (38.9) (47.5) (187.1) (305.8)
[0213] Since the slurry showed no or low free water depth after
aging, the apparent viscosities (taken as the shear rate) of the
aged samples were all within 9% of the initial slurry, the slurry
was considered stable. Since none of the samples had an apparent
viscosity (calculated as shear rate/shear stress) greater than 300
mPa-s, the slurry was considered readily flowable. The carrier
fluid was deionized water. Slurries were prepared by mixing the
solids mixture and the carrier fluid. The slurry samples were
screened for mixability and the depth of any free water formed
before and after allowing the slurry to settle for 72 hours at
static conditions. Samples which could not be mixed using the
procedure described were considered as not mixable. The samples in
which more than 5% free water formed were considered to be
excessively settling slurries. The results were plotted in the
diagram seen in FIG. 2.
[0214] From the data seen in FIG. 2, stable, mixable slurries were
generally obtained where PVF is about 0.71 or more, the ratio of
SVF/PVF is greater than 2.1*(PVF-0.71), and, where PVF is greater
than about 0.81, SVF/PVF is less than 1-2.1*(PVF-0.81). These STS
systems were obtained with a low carrier fluid viscosity without
any yield stress. By increasing the viscosity of the carrier fluid
and/or using a yield stress fluid, an STS may be obtained in some
embodiments with a lower PVF and/or a with an SVF/PVF ratio less
than 1-2.1*(PVF-0.71).
Example 5
[0215] Slot Orifice Flow Data. The multimodal STS system has an
additional benefit in these embodiments in that the smaller
particles in the voids of the larger particles act as slip
additives like mini-ball bearings, allowing the particles to roll
past each other without any requirement for relatively large spaces
between particles. This property was demonstrated by the flow of
the Table 2 STS formulation of these embodiments through a small
slot orifice. In this experiment, approximately 100 mL of the
slurry was loaded into a fluid loss cell and the bottom slot was
opened to allow fluid and solid to come out, and the fluid was
pushed by a piston using water as a hydraulic fluid supplied with
an ISCO pump at a rate of 20 mL/min. The slot at the bottom of the
cell was adjusted to different openings, 1.8 mm (0.0708 in.) and
1.5 mm (0.0591 in.). A few results of different slurries flowing
through the slots are shown in Table 5.
TABLE-US-00005 TABLE 5 Results of different slurries flowing
through different opening slots % slurry flowed through 1.8 mm %
slurry flowed through 1.5 mm Fluid (0.0708 in.) slot (0.0591 in.)
slot Slickwater with high ppa 20%* 0% 60% SVF STS 100% 50% 50% SVF
STS 100% 100% *The slurry flowed out of the cell has less solid
than what was left inside the cell, biggest particle in the
formulation is 267 microns (0.0105 in.).
[0216] It can be seen from the results that the passage of the STS
through the slot in this embodiment was facilitated, which
validates the flowability observation. With the larger slot the
ratio of slot width to largest proppant diameter was about 6.7; but
just 5.6 in the case of the smaller slot. The slickwater technique
requires a ratio of perforation diameter to proppant diameter of at
least 6, and additional enlargement for added safety to avoid
screen out usually dictates a ratio of at least 8 or 10 and does
not allow high proppant loadings. In embodiments, the flowability
of the STS through narrow flow passages (ratio of diameter of
proppant to diameter or width of flow passage less than 6, e.g.,
less than 5, less than 4 or less than 3 or a range of 2 to 6 or 3
to 5) such as perforations and fractures is similarly facilitated,
allowing a smaller ratio of perforation size to proppant size as
well as a narrower fracture that still provides transport of the
proppant to the tip, i.e., improved flowability of the proppant in
the fracture and improved penetration of the proppant-filled
fracture extending away from the wellbore into the formation. These
embodiments provide a relatively longer proppant-filled fracture
prior to screenout relative to slickwater or high-viscosity fluid
treatments.
Examples 6-9
[0217] Additional Formulations. Additional STS formulations were
prepared as shown in Table 2. Example 6 was prepared without
proppant and exemplifies a high-solids stabilized slurry without
proppant that can be used as a treatment fluid, e.g., as a spacer
fluid, pad or managed interface fluid to precede or follow a
proppant-containing treatment fluid. Example 7 was similar to
Example 6 except that it contained proppant including 100 mesh
sand. Example 8 was prepared with gelling agent instead of latex.
Example 9 was similar to Example 8, but was prepared with dispersed
oil particles instead of calcium carbonate. Examples 7-9 exemplify
treatment fluids suitable for fracturing low mobility
formations.
TABLE-US-00006 TABLE 6 STS Composition and Properties STS Example 6
Example 7 Example 8 Example 9 Components Size (.mu.m) Wt % Wt % Wt
% Wt % 40/70 proppant 210-400 -- 50-55 50-55 50-55 100 mesh sand
150 -- 8-12 8-12 8-12 Silica flour 28-33 40-45 6-12 6-12 6-12 CaCO3
2.5-3 20-25 8-12 8-12 -- Liquid Latex 0.18 20-25 8-12 -- --
Viscosifier -- 0.1-1 0.1-1 -- -- Anti-foam -- 0.05-0.5 0.05-0.5 --
-- Gelling agent -- -- -- 0.01-0.05 0.01-0.05 Dispersant --
0.05-0.5 0.05-0.5 0.05-0.5 -- Breaker -- -- -- 0.01-0.1 0.01-0.1
Breaker aid -- -- -- 0.005-0.05 0.005-0.05 Oil -- -- -- -- 2-3
Surfactant -- -- -- -- 0.1-1 Water -- 8-12 8-12 18-22 18-22
Rheology Yield Point (Pa) 11.5 8.9 15.3 13.5 K (Pa-s.sup.n) 5.41
3.09 1.42 2.39 n 0.876 0.738 0.856 0.725 Stability (static 72 h)
Stable Stable Stable Stable Leakoff control Cw (ft/min.sup.1/2)
0.0002 0.00015 0.003 0.0014 Filter cake (mm) ~1 <1 ~5 ~5 Clean
up permeability (D) ND ND 0.004-0.024 1-1.2 Fluid Properties SVF
(%) 40 (60*) 60 (70*) 60 54 (60*) Specific gravity 1.68 2 2 1.88
PPA (whole fluid) NA 14 14 13.6 Notes: ND = not determined NA = not
applicable * = including latex or oil
[0218] All of the fluids were stable, and had a yield point above
10 Pa and a viscosity less than 10 Pa-s. Rheological, leak-off
control and other fluid properties are given in Table 6.
Example 10
[0219] Crosslinked Pillars. An STS was prepared from a mix of
solids including 40/70 mesh proppant at 65 percent by volume of the
total solids (% BVOB), 100 mesh silica sand at 11% BVOB, silica
flour at 10% BVOB and 2-micron calcium carbonate at 14% BVOB. The
carrier fluid was water viscosified with guar at 2.4 g/L (20 ppt)
and containing NaOH to provide an alkaline pH conducive to
crosslinking. An overflush fluid was prepared from borate
crosslinker in water without viscosifier. The STS was pumped into a
flow visualization cell 1002 consisting of a pair of opposing glass
panes separated apart by 3 mm to simulate a fracture opening. Then
the overflush fluid was pumped into the cell. The resulting pattern
of proppant placement was observed visually and a representative
depiction is illustrated in FIG. 10. As shown, the overflush fluid
created relatively wide conductive channels 1004 due to viscous
fingering phenomena attributed to the lower viscosity of the
overflush fluid compared with the STS fluid, but also strengthened
the periphery 1006 of the pillars 1008 through crosslinking of the
guar to encapsulate the pillar.
Example 11
[0220] Crosslinked Pillars from Alkaline Overflush Fluid. This
example is similar to Example 10 except the crosslinker is
incorporated in the STS formulation without caustic and the
overflush fluid comprises aqueous NaOH without crosslinker, i.e.,
the crosslinker and the NaOH are switched between the STS and
overflush as compared with Example 10. The end result is
essentially the same as in Example 10 where the overflush fluid not
only creates wide conductive channels due to viscous fingering but
also strengthens the periphery of the islands or pillars through
crosslinking of the guar. The pillar is again encapsulated by the
crosslinked gel.
Example 12
[0221] Crosslinked Pillars from Pulsed STS Fluids. In this example,
a solid particulate crosslinker comprising CaOH, boric acid and
sodium tetraborate pentahydrate is added to the STS fluid of
Example 10 comprising guar and NaOH. As shown in FIG. 11, the
crosslinker-STS fluid is pulsed to form slugs 1010 in the flowline
1012 in a train with alternating slugs 1014 formed from the same or
a different STS fluid but without the crosslinker. When the train
of fluids is pumped into the flow visualization cell 1016, the
fluids form elongated, swirl-shaped regions 1018, 1020
corresponding to the respective slugs 1010, 1014. The presence of
the crosslinker in the slugs 1010/regions 1018 does not crosslink
the guar immediately because of the delayed release of the
crosslinker from the solid particulate relative to the
liquid/solution crosslinker as in Examples 10-11. Hence during
pumping the train of fluids remains ungelled; however, once the
train of fluid is placed in a fracture the regions 1018 develop
localized gelling due to the release of the crosslinker in the STS
with time, increased temperature, etc., and there are also STS
regions 1020 that are non-gelled STS. The non-gelled STS regions
1020 are considered to be more conductive channels compared with
the gelled STS regions 1018. Furthermore, the proppant in the
gelled regions 1018 does not sediment in the crosslinked gel,
whereas the proppant in the non-gelled areas 1020 in embodiments
sediments with time to enhance the conductivity of the non-gelled
channels 1020. The STS fluid formulation in embodiments is adjusted
to promote sedimentation through dilution or by incorporating a
destabilization agent thus making it more conductive compared with
the gelled regions 1018. The solid crosslinker is used in this
example to delay the crosslinking and additionally it may be
encapsulated with different material to control the rate of release
that is temperature, pressure or chemistry dependent.
Example 13
[0222] Crosslinked Pillars from Hydraulic Cement Treatment. This
example is similar to Example 12 except that the slugs 1010 are
freshly prepared (uncured) hydraulic cement slurry or a slurry such
as an STS containing hydraulic cement particulates, and the slugs
1014 comprise an STS. The pulsed cement creates local dehydration
within the STS fluid(s) placed inside the fracture, thus creating
inhomogeneous fluid placement and strengthening of pillars 1018
comprised of cured, hydrated cement and STS fluid in its vicinity.
The cement containing areas 1018 in the fracture are less
conductive relative to areas 1020 without cement, or the cement-STS
slug 1010 may be chemically formulated such that both of the areas
1018, 1020 are highly conductive relative to the formation of the
fracture.
Example 14
[0223] Crosslinked Pillars from SAP Treatment. In this example an
STS with a solids mix similar to that of Example 11 was formulated
with polyacrylamide superabsorbent polymer (SAP) particles capable
of absorbing 500 times their weight of water (from 30-60 times
initial volume). The STS includes means to delay swelling of the
SAP until after placement in the fracture, and the rate of
dehydration is controlled by selecting the SAP, valence cations in
the aqueous carrier, encapsulant polymer, and/or chemical or
physical trigger(s) to initiate the aqueous fluid absorption. The
SAP-STS was pumped into the flow visualization cell 1030 to
simulate a fracture opening and the SAP allowed to swell in a
simulated shut-in, dehydrating localized regions of the STS. The
resulting pattern of proppant placement was observed visually and a
representative depiction is illustrated in FIG. 12. As shown, the
SAP-proppant agglomerants formed relatively small pillars 1032
within a network of conductive channels 1034 corresponding to
SAP-free regions.
[0224] While the disclosure has provided specific and detailed
descriptions to various embodiments, the same is to be considered
as illustrative and not restrictive in character. Only certain
example embodiments have been shown and described. Those skilled in
the art will appreciate that many modifications are possible in the
example embodiments without materially departing from the
disclosure. Accordingly, all such modifications are intended to be
included within the scope of this disclosure as defined in the
following claims.
[0225] In reading the claims, it is intended that when words such
as "a," "an," "at least one," or "at least one portion" are used
there is no intention to limit the claim to only one item unless
specifically stated to the contrary in the claim. When the language
"at least a portion" and/or "a portion" is used the item can
include a portion and/or the entire item unless specifically stated
to the contrary. In the claims, means-plus-function clauses are
intended to cover the structures described herein as performing the
recited function and not only structural equivalents, but also
equivalent structures. For example, although a nail and a screw may
not be structural equivalents in that a nail employs a cylindrical
surface to secure wooden parts together, whereas a screw employs a
helical surface, in the environment of fastening wooden parts, a
nail and a screw may be equivalent structures. It is the express
intention of the applicant not to invoke 35 U.S.C. .sctn.112,
paragraph 6 for any limitations of any of the claims herein, except
for those in which the claim expressly uses the words `means for`
together with an associated function.
* * * * *
References