U.S. patent application number 15/205478 was filed with the patent office on 2016-11-03 for pickering emulsion treatment fluid.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Yiyan Chen, Anthony Loiseau.
Application Number | 20160319188 15/205478 |
Document ID | / |
Family ID | 52389492 |
Filed Date | 2016-11-03 |
United States Patent
Application |
20160319188 |
Kind Code |
A1 |
Loiseau; Anthony ; et
al. |
November 3, 2016 |
PICKERING EMULSION TREATMENT FLUID
Abstract
A well treatment fluid comprising a Pickering particle emulsion
comprising particles of a first liquid phase dispersed in a
continuous second liquid phase, and comprising a plurality of
colloidal particles adsorbed to a liquid-liquid interface between
the first liquid phase and the second liquid phase. Methods,
equipment and/or systems for treating a subterranean formation
utilizing such treatment fluids are also disclosed.
Inventors: |
Loiseau; Anthony; (Rio de
Janeiro, BR) ; Chen; Yiyan; (Sugar Land, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
52389492 |
Appl. No.: |
15/205478 |
Filed: |
July 8, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13950483 |
Jul 25, 2013 |
9388335 |
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15205478 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C09K 2208/08 20130101;
C09K 8/80 20130101; C09K 8/70 20130101; E21B 43/26 20130101; C09K
8/92 20130101; E21B 43/267 20130101 |
International
Class: |
C09K 8/70 20060101
C09K008/70; E21B 43/267 20060101 E21B043/267; E21B 43/26 20060101
E21B043/26; C09K 8/80 20060101 C09K008/80 |
Claims
1.-14. (canceled)
15. A method, comprising: dispersing a first liquid phase in a
second liquid phase in the presence of a plurality of colloidal
particles under conditions sufficient to produce a Pickering
emulsion comprising a plurality of Pickering emulsion particles
comprising the first liquid phase dispersed in the continuous
second liquid phase, and comprising at least a portion of the
plurality of colloidal particles adsorbed to a liquid-liquid
interface between the first liquid phase and the second liquid
phase; mixing the Pickering emulsion in a carrier fluid to produce
a treatment fluid comprising a plurality of particles having an
Apollonianistic particle size distribution comprising particles of
the Pickering emulsion; and circulating the treatment fluid into a
wellbore.
16. The method of claim 15, further comprising forming a pack of
the solids in the wellbore, wherein the pack comprises proppant and
at least one particle size distribution mode comprising the
particles of the Pickering emulsion.
17. The method of claim 16, wherein at least a portion of the
plurality of colloidal particles is freely dispersed in the
treatment fluid, and wherein the pack comprises at least one
particle size distribution mode of the freely dispersed colloidal
particles.
18. The method of claim 16, further comprising removing at least a
portion of the particles from the pack to form a permeable proppant
pack.
19. The method of claim 18, further comprising producing or
injecting a fluid through the permeable proppant pack.
20. The method of claim 19, wherein the permeable proppant pack is
disposed in a fracture.
Description
BACKGROUND
[0001] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0002] The use of treatment fluids in general, and high solids
content treatment fluids in particular, may benefit from very good
leak off control properties to inhibit fluid loss, as well as good
stability, minimal settling of solids, suitable rheological
properties for pumping with oilfield equipment, and/or good
permeability of a solids pack after placement. Accordingly, there
is a demand for further improvements in this area of
technology.
SUMMARY
[0003] Control over fluid loss control and cleanup may be required
when using HSCF and other systems. Treatment fluids may comprise
emulsion droplets having various particle size distribution modes,
which may be used as "particles" in a treatment fluid to provide
leak off control of high solid concentration fluids, and the like.
In an embodiment, the emulsion particles of a first liquid phase
dispersed in a continuous second liquid phase are stabilized with
colloidal particles adsorbed at the first liquid/second liquid
interface in what is referred to as a "Pickering Emulsion" to
produce a treatment fluid. In an embodiment, the colloidal
particles comprise hydrolyzable particles. In an embodiment, the
dispersed phase droplets have flexibility (pliability) to deform,
thus seal non-exact size pore throats. The treatment fluid
disclosed herein is suitable for use alone, or in combination with
HSCF and other solid particle systems. In an embodiment, the
dispersed phase droplets are labile, such that they may be removed
or destroyed after well stimulation or the like to produce a
permeable pack. The removal or destruction of the emulsion
particles (i.e., the particles comprising the first liquid phase
dispersed in the continuous second liquid phase which are
stabilized with the colloidal particles adsorbed at the first
liquid/second liquid interface) may result from diffusion of oil or
another component to destroy the Pickering emulsion, via hydrolysis
of the colloidal particles via pH modification, temperature
changes, phase inversion, solvent solubility, surface property
change, and/or the like.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] 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.
[0005] FIG. 1 shows a schematic slurry state progression chart for
a treatment fluid according to some embodiments of the current
application.
[0006] FIG. 2 illustrates fluid stability regions for a treatment
fluid according to some embodiments of the current application.
[0007] FIG. 3 shows a schematic representation of the wellsite
equipment configuration with onsite mixing of a treatment fluid
according to some embodiments of the current application.
[0008] FIG. 4 shows a contact angle of less than 90.degree. of a
spherical particle adsorbed to a liquid-liquid interface according
to an embodiment of the current application.
[0009] FIG. 5 shows a contact angle of 90.degree. of a spherical
particle adsorbed to a liquid-liquid interface according to an
embodiment of the current application.
[0010] FIG. 6 shows a contact angle of greater than 90.degree. of a
spherical particle adsorbed to a liquid-liquid interface according
to an embodiment of the current application.
[0011] FIG. 7 shows the contact angle measurement of a spherical
particle adsorbed to a liquid-liquid interface according to an
embodiment of the current application.
[0012] FIG. 8 shows a droplet of a first liquid phase dispersed in
a continuous second liquid phase, and comprising a plurality of
colloidal particles adsorbed to a liquid-liquid interface between
the first liquid phase and the second liquid phase according to an
embodiment of the current application.
DETAILED DESCRIPTION OF SOME ILLUSTRATIVE AN EMBODIMENTS
[0013] 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.
[0014] As used herein, "an embodiment" 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 embodiment, 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.
[0015] 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.
[0016] 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., as well as
non-oilfield well treatment operations can utilize and benefit as
well from the instant disclosure.
[0017] 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.
[0018] 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 or low-shear (5.11 s.sup.-1) viscosity less than 1000 Pa 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.
[0019] As used herein, the terms "Apollonianistic,"
"Apollonianistic packing," "Apollonianistic rule," "Apollonianistic
particle size distribution," "Apollonianistic PSD" and similar
terms refer to the particles present in the fluid in the absence of
the carrier fluid having a multimodal volume-averaged particle size
distribution with particle size distribution (PSD) modes that are
not necessarily strictly Apollonian wherein either (1) a first PSD
mode comprises particulates having a volume-averaged median size at
least 1.5 times larger, or 3 times larger than the volume-average
median size of at least a second PSD mode such that a packed volume
fraction (PVF) (as defined herein) of the particulates present in
the mixture exceeds 0.75 or (2) the particle mixture comprises at
least three PSD modes, wherein a first amount of particulates have
a first PSD mode, a second amount of particulates have a second PSD
mode, and a third amount of particulates have a third PSD mode,
wherein the first PSD mode is from 1.5 to 25 times, or from 2 to 10
times larger than the second PSD mode, and wherein the second PSD
mode is at least 1.5 times larger than the third PSD mode.
[0020] 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 slurry solids volume
fraction (SVF) herein, the particle volume includes the volume of
any colloidal and/or submicron particles.
[0021] Here, the porosity, .phi., is the void fraction of the
randomly packed particulates. 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 particulates.
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 the particles present in the fluid. 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 distribution mode
and/or a range(s) of particle sizes. The smaller particles can fit
in the void spaces between the larger ones thus increasing the PVF
of the particulates.
[0022] An Apollonianistic particle size distribution increases the
PVF to above 0.74 by using a multimodal particle mixture, for
example, coarse, medium and fine particles in specific volume
ratios, where the smaller particles are selected to fit in the void
spaces between the medium-size particles, and the medium size
particles are selected to fit in the void space between the coarse
particles. An Apollonianistic particle size distribution may, for
example, include 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.
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.
[0023] For purposes herein, the slurry solid volume fraction (SVF)
is defined as
SVF=Particle volume/(Particle volume+Liquid volume)
[0024] Accordingly, the SVF/PVF ratio is equal to:
SVF/PVF=(Particle volume+Non-particle Volume)/(Particle
volume+Liquid volume)
[0025] 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, or stated another
way, when the liquid volume is equal to the void fraction of the
randomly packed particulates. 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 0.99. In
other words, the void volume may be less than the liquid volume. In
this condition, 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 an embodiment, the
higher the PVF, the lower the SVF/PVF ratio should be to obtain a
flowable slurry i.e., more fluid is present than necessary to file
the void volume of the randomly packed particles.
[0026] FIG. 1 shows a slurry state progression chart for a system
100 having a particle mix with added fluid phase. The first fluid
102 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 102 is not flowable. The second fluid 104 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 104 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 106 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 106 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 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).
[0027] The fourth fluid 108 shown in FIG. 1 has more fluid phase
than the third fluid 106, to the point where the fourth fluid 108
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 108). 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. 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.
[0028] For purposes herein, the Apollonianistic particle size
distribution of emulsified particles which are not solids, but
which are, in-fact, liquid droplets of a discontinuous liquid phase
dispersed in a continuous liquid phase assumes that the particles
are spherical, and are not deformed when incorporated into a pack.
However, in describing the packed volume occupied by a plurality of
particle size distribution modes which include emulsion particles,
the treatment fluid may be characterized according to a dispersed
particle volume fraction (DPVF), which refers to the volume
fraction of a fluid occupied by the dispersed particles including
emulsified liquids, solids, and the like. Accordingly, for purposes
herein, the DPVF is defined as the ratio of the packed volume
fraction (PVF) of all the particulates divided by the total volume
of the fluid. A particle emulsion comprising particles having an
Apollonianistic particle size distribution (of particles) is
defined as having a DPVF of at least 40%, or at least 50%, or at
least 60%, or at least 70%, or at least 80%, or at least 90%, or at
least 95%.
[0029] "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-Bulkley 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 is equal to 1, the
Herschel-Bulkley 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-Bulkley 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.
[0030] For purposes herein "contact angle" refers to the angle,
conventionally measured through the liquid of the continuous phase,
where a liquid interface meets a solid surface. It quantifies the
wettability of a solid surface by a liquid via the Young
equation:
.theta. c = arccos ( r A cos .theta. A + r R cos .theta. R r A + r
R ) ##EQU00001##
wherein .theta..sub.A is the maximal contact angle; .theta..sub.R
is the minimal contact angle; and
r A = ( sin 3 .theta. A 2 - 3 cos .theta. A + cos 3 .theta. A ) 1 /
3 ; r R = ( sin 3 .theta. R 2 - 3 cos .theta. R + cos 3 .theta. R )
1 / 3 ##EQU00002##
[0031] A contact angle ".theta." of greater than 0.degree. and less
than 90.degree. is shown in FIG. 4, a contact angle .theta. of
90.degree. is shown in FIG. 5, and a contact angle .theta. of
greater than 90.degree. is shown in FIG. 6. For purposes herein, a
contact angle .theta. of 0 indicates perfect wettability; a contact
angle .theta. of greater than 0 and less than 90.degree. indicates
high wettability; a contact angle .theta. of greater than or equal
to 90.degree. and less than 150.degree. indicates low wettability;
and a contact angle .theta. of 180.degree. indicates a perfectly
non-wetting interaction.
[0032] In an embodiment, the contact angle can be measured using
the gel-trapping technique as described by technique as described
by Paunov (Langmuir, 2003, 19, 7970-7976) or alternatively by using
commercial contact angle measurement apparatus such as the
Dataphysics OCA20, or other suitable instrumentation.
[0033] For purposes herein, a "Pickering emulsion" refers to an
emulsion comprising a first liquid phase dispersed in a second
continuous liquid phase that is stabilized by solid particles (for
example colloidal silica) which adsorb onto the interface between
the two phases, as described by Ramsden, W. Separation of Solids in
the Surface-Layers of Solutions and `Suspensions` (See. Ramsden,
W., Proc. R. Soc. London 1903, 72, 156-164; and Pickering, S. U.
Emulsions. J. Chem. Soc. 1907, 91, 2001-2021).
[0034] For purposes herein, a particle may be substantially round
and spherical, and/or may have varying degrees of sphericity and
roundness, according to the API RP-60 sphericity and roundness
index. Particles may be described according to an aspect ratio,
which for purposes herein is defined as the ratio of the longest
dimension of the particle to the shortest dimension of the
particle.
[0035] 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 an embodiment, 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.
[0036] In an embodiment, 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 an embodiment, 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, xanthan and 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.
[0037] In an embodiment, the particles in the treatment fluids 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 an
embodiment, the particles contain a bimodal mixture of two
particles; in an embodiment, the particles contain a trimodal
mixture of three particles; in an embodiment, the particles contain
a tetramodal mixture of four particles; in an embodiment, 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.
[0038] "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.
[0039] "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 an embodiment, 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.
[0040] 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 an embodiment, the
proppant of the current application, when present, has a density
greater than 2.45 g/mL, or greater than 3 g/mL, or greater than
3.25 g/mL, e.g., 2.5-3.5 g/mL, such as sand, ceramic, sintered
bauxite or resin coated proppant. In an embodiment, 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.
[0041] In an embodiment, the treatment fluid comprises a particle
emulsion comprising an Apollonianistic particle size distribution
of particles of a first liquid phase dispersed in a continuous
second liquid phase, the particles comprising a plurality of
colloidal particles adsorbed to a liquid-liquid interface between
the first liquid phase and the second liquid phase.
[0042] In an embodiment, the treatment fluid comprises a particle
emulsion comprising particles of a first liquid phase dispersed in
a continuous second liquid phase, and comprising a plurality of
hydrolyzable colloidal particles adsorbed to a liquid-liquid
interface between the first liquid phase and the second liquid
phase.
[0043] In an embodiment, the colloidal particles have a particle
size distribution mode from 0.005 to 100 microns. In an embodiment,
the colloidal particles comprise an aspect ratio from 1.1 to about
1000. In an embodiment, the colloidal particles comprise a contact
angle of about 20.degree. to about 150.degree., or about 60.degree.
to about 120.degree., when determined at the colloidal
particle/first liquid phase/second liquid phase boundary. In an
embodiment, the colloidal particles have an average length from
about 0.001 microns to about 100 microns.
[0044] In an embodiment, the colloidal particles are hydrolyzable.
In an embodiment, the colloidal particles comprise wax,
C.sub.1-C.sub.20 aliphatic polyester, polylactic acid, polyglycolic
acid, polycaprolactone, polyhydroxybutyrate,
polyhydroxybutyrate-valerate copolymer, C.sub.1-C.sub.20 aliphatic
polycarbonate, polyphosphazene, polysaccharide, dextran, cellulose,
chitin, chitosan, protein, polyamino acid, polyethylene oxide,
microcrystalline cellulose, natural plant fibers, silk, stearic
acid, polyvinyl pyrrolidone, calcium carbonate, calcium sulfate,
zinc oxide, titanium dioxide, magnesium oxide, magnesium sulfate,
magnesium hydroxide, magnesium borate, aluminum borate, potassium
titanate, barium titanate, hydroxyapatite, attapulgite, iron
oxides, copper oxides, aluminum oxide, precipitated silica, fumed
silica, or a combination thereof.
[0045] In an embodiment, the colloidal particles comprise fibers
having an aspect ratio from about 10 to about 1000, which have been
modified to comprise a contact angle of about 60.degree. to about
120.degree., when determined at the hydrolyzable colloidal
particle/first liquid phase/second liquid phase boundary. In an
embodiment, the hydrolyzable colloidal particle fibers comprise
microcrystalline cellulose, natural plant fibers, silk, stearic
acid, polyhydroxybutyrate-valerate polymer, polyvinyl pyrrolidone
polymer, polycaprolactone polymer, polylactic acid, polyglycolic
acid, calcium carbonate, calcium sulfate, zinc oxide, titanium
dioxide, magnesium oxide, magnesium sulfate, magnesium hydroxide,
magnesium borate, aluminum borate, potassium titanate, barium
titanate, hydroxyapatite, attapulgite, or a combination
thereof.
[0046] In an embodiment, the treatment fluid may further comprise
at least one Ostwald ripening inhibitor which is soluble or
miscible in the first phase or which itself serves as the first
phase. In an embodiment, the treatment fluid may comprise from 1 to
20 parts per 100 parts by weight of one or more of a dispersant, a
surfactant, a viscosifier, a defoamer, or a combination thereof,
based on the total amount of the carrier fluid present in the
treatment fluid.
[0047] In an embodiment, the treatment fluid may comprise an
Apollonianistic solids mixture, wherein at least one particle size
distribution mode comprises the Pickering emulsion particles, i.e.,
the particles comprising the first liquid phase stabilized by the
colloidal particles. In an embodiment, the Apollonianistic solids
mixture comprises first and second particle size distribution modes
wherein the first particle size distribution mode is at least three
times larger than the second particle size distribution mode such
that a PVF of the solids mixture exceeds 0.75. In an embodiment,
the first particle size distribution mode is smaller than a
particle size distribution mode of a proppant. In an embodiment,
the treatment fluid may further comprise a solids mixture
comprising hydrolyzable particles, wherein the hydrolyzable
particles may be present as colloidal particles adsorbed at the
first liquid/second liquid interface, and/or freely dispersed in
the continuous phase, as particles having one or more particle size
distribution modes of an Apollonianistic solids mixture, or a
combination thereof.
[0048] Fluid loss control is a concern in utilization of HSCF and
other solid systems since small amount of fluid loss may render the
fluid immobile. Fluid loss control for HSCF and other systems may
be achieved by a variety of methods. One method is to construct the
HSCF following a certain particle size distribution, where the
holes created by bigger particles are filled by smaller particles.
It has been demonstrated that if the particles construction follows
Apollonian packing parameters, good leak off control can be
achieved. Another method includes use of polymeric materials e.g.,
latex, where upon enough pressure differentials; the latex or other
polymer will film and form an impermeable barrier.
[0049] For Apollonian packing of particles to stop fluid loss, the
particle sizes need to extend to a few nanometer size when the gap
or capillaries formed in these packing system will become small
enough that close to 10,000 psi capillary force is present. This
pressure is typically suitable to stop fluid loss. Forming an ideal
gradient for the particles to achieve the fluid loss control is
problematic. In addition, the small particles may need to be
removed to produce a pack having permeability to improve fluid
production. Latex is problematic in this respect. Treatment fluids
comprising Pickering emulsion according to an embodiment disclosed
herein may be utilized as part of an Apollonian packing, and the
colloidal particles may function as one or more of the fluid
control agents.
[0050] In an embodiment, the Pickering emulsion particles have a
particle size distribution of greater than or equal to about 1
micron, or from about 1 micron to about 100 microns. As such, in an
embodiment, the Pickering emulsion particles fill the medium
particle size distribution typically required for Apollonian
packing suitable for stopping fluid loss in treatment fluids.
However, in an embodiment, the free colloidal particles (those
which are present in excess of those adsorbed at the first
liquid/second liquid interface) that are present in a treatment
fluid may function as one or more of the small particles PSD modes
in the Apollonian packing to stop fluid loss.
[0051] In an embodiment, the Pickering emulsion particles have a
particle size distribution mode in a size range above what would be
produced by a typical emulsion. However, since the Pickering
emulsion particles are fluid, they may fill interstices between
proppant or other particles, and the colloidal particles may then
fill the remaining interstices to complete the Apollonian packing.
In an embodiment, the treatment fluid may comprise an
Apollonianistic particle size distribution comprising, or
consisting essentially of a proppant, one or more PSD modes
comprising a Pickering emulsion, and colloidal particles, wherein
the Pickering emulsion comprises particles of a first liquid phase
dispersed in a continuous second liquid phase, and comprising a
plurality of a portion of the colloidal particles adsorbed to a
liquid-liquid interface between the first liquid phase and the
second liquid phase. In such an embodiment everything present can
be flowable, or everything can be flowable except the proppant,
providing facile cleanup without having to degrade any of the
particles present.
[0052] In an embodiment, the Pickering emulsion particles may be
"broken" by mere alteration of the surface properties to break the
emulsion present in the fluid. In and embodiment, the viscosity
and/or composition of the continuous phase may be manipulated to
break the emulsion and thus, remove particles present in a downhole
pack or the like
[0053] In an embodiment, a treatment fluid comprises a Pickering
emulsion, which comprises particles having a particle size
distribution mode from about 0.5 micron to about 500 microns. In an
embodiment, a treatment fluid comprises a Pickering emulsion, which
comprises particles having a particle size distribution mode of
greater than or equal to about 1 micron, or greater than or equal
to about 5 microns, or greater than or equal to about 10 microns,
or greater than or equal to about 50 microns, and having a particle
size distribution mode of less than or equal to about 100 microns,
or less than or equal to about 50 microns, or less than or equal to
about 10 microns.
[0054] In an embodiment, a treatment fluid comprises a Pickering
emulsion, which comprises solid colloidal particles of intermediate
wettability (i.e., having a contact angle from about 60.degree. to
about 120.degree. at a boundary of the colloidal particle/first
liquid phase/second liquid phase interface) in a size range from
about 5 nanometers to about 100 micrometers, which are absorbed or
otherwise attached to a liquid-liquid interface of a first liquid
phase dispersed in a second continuous liquid phase, to provide
emulsion stability.
[0055] In an embodiment, a treatment fluid comprises a plurality of
colloidal particles having a particle size distribution mode from
about 0.005 microns to about 100 microns. In an embodiment, a
treatment fluid comprises colloidal particles having a particle
size distribution mode of greater than or equal to about 0.01
microns, or greater than or equal to about 0.05 microns, or greater
than or equal to about 0.1 microns, or greater than or equal to
about 0.5 microns, and having a particle size distribution mode of
less than or equal to about 10 microns, or less than or equal to
about 5 microns, or less than or equal to about 1 micron. In an
embodiment, at least a portion of the colloidal particles present
in the fluid are absorbed or otherwise attached to a liquid-liquid
interface of a first liquid phase dispersed in a second continuous
liquid phase, and at least a portion of the colloidal particles
present in the fluid is freely dispersed in the fluid.
[0056] Accordingly, in an embodiment, at least a portion of the
plurality of colloidal particles is freely dispersed in the second
liquid phase, and which comprises at least one particle size
distribution mode of an Apollonianistic particle size distribution
present in the treatment fluid. For purposes herein, the plurality
of colloidal particles freely dispersed in the second liquid phase
refers to colloidal particles which are not present, or which have
not adsorbed to the liquid/liquid interface between the first
liquid phase and the second liquid phase, but instead are merely
dispersed as discrete particles in the second liquid phase.
[0057] In an embodiment, the colloidal particles must be selected
to comprise an appropriate size, wettability and concentration in
the emulsion in order for particles to stabilize the Pickering
emulsion. In an embodiment, the colloidal particles may be present
in an amount which exceeds the amount required to stabilize the
emulsion, such that the freely dispersed colloidal particles may
function as fluid loss control agents, and/or the like. Other
factors contributing to the stability of the emulsion may include
the pH and presence of ions in the water phase as well as the
presence of any other emulsifiers. In an embodiment, these factors
may be manipulated to produce an inversion in the type of the
emulsion or otherwise destroy the emulsion particles. The
interactions of the particles with each other are also important.
Accordingly, different kinds of particles may be selected to
stabilize the emulsion depending on the type of emulsion
(oil-in-water, water-in-oil) desired. In an embodiment, the
particles may be treated to provide wetting of the particles to
further stabilize the emulsion.
[0058] In an embodiment, the Pickering emulsions may be essentially
free of a surfactant, comprising less than about 0.1 wt % based on
the total weight of the emulsion, or may include one or more
surfactants to provide wetting of the colloidal particles,
dispersion of the discontinuous phase, and/or the like. In an
embodiment, the Pickering emulsion comprises colloidal particles
which comprise a hydrolyzable polymer, also referred to as a
"labile polymer" or a "degradable polymer", which refers to a
polymer in which the molecular weight is reduced by cleaving of at
least some of the bonds between at least some of the polymerized
monomers upon contact with a particular agent, i.e., a solvent, an
acid, a base, an oxidizing agent, a reducing agent, or any
combination thereof.
[0059] In an embodiment, the colloidal particle may comprise a
metallic salt, oxide, or other inorganic compound which is
degradable under various conditions of pH, temperature, solvent
polarity, and/or the like. For purposes herein, a "hydrolyzable"
colloidal particle, whether an inorganic moiety or a polymeric
moiety, need not undergo actual chemical hydrolysis (i.e., the
addition of water across a chemical bond), but may undergo cleavage
of a chemical bond or crosslink reducing the overall molecular
weight of the polymer, or size of the particle. Upon hydrolysis, a
"hydrolyzable" or degradable colloidal particle may have an
increased water solubility, and/or a reduction in actual size of
the particle.
[0060] In an embodiment, the colloidal particles have a lower
solubility in the dispersed phase relative to the continuous phase.
In an embodiment, the colloidal particle has a solubility of less
than 1 wt % in water at 25.degree. C., or less than 0.1 wt % in
water at 25.degree. C. The colloidal particle may, however, be at
least partially soluble or otherwise degraded by the environment in
which the particle is located, including changing the pH in the
environment, e.g., in the solids pack. For example, a polymeric
colloidal particle may be insoluble at a neutral pH, but may become
water soluble at a high, and/or at a low pH.
[0061] In an embodiment, the colloidal particle is soluble in
acidic fluids having a pH of less than 2, in basic fluids having a
pH greater than 10, or a combination thereof. In an embodiment, the
treatment fluid may further include an acid precursor, a base
precursor, or the like, which is optionally sparingly soluble
and/or encapsulated such that upon contact with a fluid, the acid
or base is released after an appropriate time, thereby resulting in
the at least partial removal of any hydrolyzable particles which
may be present, which in-turn may destabilize the Pickering
emulsion to remove the emulsion particles from a pack or other
formation. In an embodiment, the colloidal particle is acid labile.
In an embodiment the hydrolysis products of the colloidal particle
may be water soluble.
[0062] In an embodiment, the colloidal particles comprise a
hydrolyzable or otherwise labile polymer. In an embodiment, the
hydrolyzable polymer comprises a polyester. In an embodiment, the
colloidal particles comprise polylactic acid, polyglycolic acid,
polycarprolactone, polybutylene succinate, polybutylene
succinate-co-adipate, copolymers thereof, or a combination thereof.
In an embodiment, the colloidal particles comprise a surface
modified polymer.
[0063] In an embodiment, the Pickering emulsion and/or a treatment
fluid comprising the Pickering emulsion according to an embodiment
disclosed herein may be essentially free of surfactant.
Accordingly, in an embodiment, the Pickering emulsion and/or a
treatment fluid comprising the Pickering emulsion may comprise less
than about 0.1 wt % of a surfactant.
[0064] In an embodiment, the emulsion may include one or more
surfactants. Suitable surfactants include nonionic surfactants,
which may be one or more of alkyl alcohol ethoxylates, alkyl phenol
ethoxylates, alkyl acid ethoxylates, alkyl amine ethoxylates,
sorbitan alkanoates, ethoxylated sorbitan alkanoates, or the like.
The nonionic surfactant in an embodiment may be an alkoxylate such
as octyl phenol ethoxylate or a polyoxyalkylene such as
polyethylene glycol or polypropylene glycol, or a mixture of an
alkoxylate or a plurality of alkoxylates with a polyoxyalkylene or
a plurality of polyoxyalkylenes, e.g., a mixture of octyl phenol
ethoxylate and polyethylene glycol. The nonionic surfactant may
also function as a plasticizer.
[0065] In an embodiment, the continuous phase has a contact angle
with the colloidal particles of less than 90.degree. and the
discontinuous phase has a contact angle with the colloidal
particles of greater than or equal to 90.degree..
[0066] In an embodiment, the discontinuous phase has a contact
angle with the colloidal particles of less than 90.degree. and the
continuous phase has a contact angle with the colloidal particles
of greater than or equal to 90.degree..
[0067] As shown in FIG. 7, the contact angle .theta. (702) is
measured at the colloidal particle/first liquid phase/second liquid
phase boundary through the continuous second phase 704, (e.g., an
aqueous phase) of a spherical particle 706 having a radius "a"
present at the liquid-liquid interface 710 between the aqueous
phase 704 and an first dispersed phase 708 (e.g., an oil
phase).
[0068] FIG. 8 shows the contact angle 802 determined between a
spherical particle (e.g., a droplet) having a radius "R" of a first
liquid phase 808 dispersed, in a continuous second liquid phase
804, and comprising a plurality of colloidal particles 806 adsorbed
to a liquid-liquid interface 810 between the first liquid phase 808
and the second liquid phase 804 according to an embodiment of the
current application.
[0069] In an embodiment, the colloidal particles may have, or may
have been modified so as to impart surface-active properties onto
the particles to produce a contact angle from 0.degree. to
150.degree., or greater than about 10.degree., or about 20.degree.,
or about 30.degree., or about 40.degree., or about 50.degree.,
about 60.degree., and less than or equal to about 140.degree., or
about 130.degree., or about 120.degree., or about 100.degree., or
about 90.degree.. In an embodiment, the colloidal particles may
have, or may have been modified so as to impart surface-active
properties onto the particles to produce a contact angle from about
60.degree. to about 120.degree. with both the continuous phase and
the discontinuous phase of the emulsion.
[0070] In an embodiment, the oil phase comprises a liquid with
intermediate hydrophobicity so that it does not substantially
dissolve or become miscible with water and is not so hydrophobic
that the hydrolyzable colloidal particles are unable to efficiently
contact both the oil and water phases and thus remain at the
interface. In an embodiment, the oil phase has an octanol-water
partition coefficient (or log P) above 1 and below 7, or below
5.
[0071] In an embodiment, the colloidal particles are selected to be
small enough so that they can coat the surfaces of the dispersed
phase droplets, sufficiently small for good dispersion stability
against sedimentation when diluted for use and small enough to
provide an even product distribution at the target site. The
colloidal particles may also be selected to comprise sufficient
affinity for both the liquids forming the dispersed and continuous
phases such that they are able to adsorb to the liquid-liquid
interface and thereby stabilize the emulsion.
[0072] This wetting characteristic, particle shape and suitability
of colloidal particles for Pickering emulsion stabilization
according to the instant disclosure may, in an embodiment, be
readily assessed in formulations of sufficiently low viscosity
(below about 2000 centipoise) to be useful in most fluids by
combining the two immiscible liquid phases and the colloidal
particle, and providing sufficient mechanical agitation to form an
emulsion. If the resulting emulsion exhibits no substantial droplet
coalescence over a period of 2 or more hours at a particular
temperature, as determined by the growth of a liquid layer
containing only the liquid that was earlier present in the disperse
phase, then the colloidal particle may comprise sufficient affinity
for the liquid-liquid interface to stabilize the Pickering emulsion
of the instant disclosure against coalescence.
[0073] In an embodiment, the affinity of the colloidal particle for
the liquid-liquid interface of a particular fluid can be increased,
and the emulsion stability improved, by adding one or more water
soluble electrolytes or non-electrolytes to the continuous aqueous
phase, as may be readily determined by conventional experimental
methods. It is also similarly possible to improve the affinity of
the colloidal particle for the liquid-liquid interface by adding a
co-solvent that partitions preferentially into the disperse phase,
that is a co-solvent having a dispersed phase/continuous phase
partition log P of greater than about 1, as may be readily
determined by one of skill in the art.
[0074] A wide variety of solid materials may be used as colloidal
particles for the treatment fluids according to the instant
disclosure. In an embodiment, the colloidal particles may comprise
carbon black, metal oxides, metal hydroxides, metal carbonates,
metal sulfates, polymers which are insoluble in any of the
components of the treatment fluids, silica, clays, and combinations
thereof.
[0075] In an embodiment, the colloidal particles comprise wax,
C.sub.1-C.sub.20 aliphatic polyester, polylactic acid, polyglycolic
acid, polycaprolactone, polyhydroxybutyrate,
polyhydroxybutyrate-valerate copolymer, C.sub.1-C.sub.20 aliphatic
polycarbonate, polyphosphazene, polysaccharide, dextran, cellulose,
chitin, chitosan, protein, polyamino acid, polyethylene oxide,
microcrystalline cellulose, natural plant fibers, silk, stearic
acid, polyvinyl pyrrolidone, calcium carbonate, calcium sulfate,
zinc oxide, titanium dioxide, magnesium oxide, magnesium sulfate,
magnesium hydroxide, magnesium borate, aluminum borate, potassium
titanate, barium titanate, hydroxyapatite, attapulgite, iron
oxides, copper oxides, aluminum oxide, precipitated silica, fumed
silica, or a combination thereof.
[0076] In an embodiment, the colloidal particles may be
characterized as having a low solubility in both the continuous and
disperse liquid phases, i.e., below about 100 ppm at room
temperature, and can be prepared at a suitable particle size, and
have suitable wetting properties for the liquid-liquid interface as
described herein. It is also possible that one or more particles of
a PSD mode can serve as the colloidal particle.
[0077] In an embodiment, the colloidal particle may comprise a
surface modified solid, for example fumed or precipitated silica
modified by the presence of dimethyldichlorosilane,
hexadecylsilane, aluminum oxide or by alkane decoration. Polymers
suitable for use as colloidal particles include polymeric fibers
which have been modified so as to impart surface-active properties
onto the fibers, and the like.
[0078] In an embodiment, the polymeric fibers suitable for use as
colloidal particles may have been modified so as to impart
surface-active properties onto said fibres to produce a contact
angle from 0.degree. to 150.degree., or greater than about
10.degree., or about 20.degree., or about 30.degree., or about
40.degree., or about 50.degree., about 60.degree., and less than or
equal to about 140.degree., or about 130.degree., or about
120.degree., or about 100.degree., or about 90.degree.. In an
embodiment, the polymeric fibers suitable for use as colloidal
particles may have been modified so as to impart surface-active
properties onto said fibres to produce a contact angle from about
60.degree. to about 120.degree. with both the continuous phase and
the discontinuous phase of the emulsion.
[0079] In an embodiment, the colloidal particles, which include
polymeric fibers, may comprise a rod-like (fibril) shape, and
comprise a particle contact angle at an oil/water or air/water
interface which is from about 60.degree. to 120.degree., or about
85.degree. to 90.degree.. For purposes herein, "fibre" refers to
any particulate structure having an aspect ratio between the length
and the diameter ranges from 10 to infinite, wherein the diameter
refers to the largest distance of the cross-section. The materials
of the "fibre" substance can be organic, inorganic,
polymeric/and/or macromolecular. In an embodiment the fibre
topology may be liner or branched (star-like). The aspect ratio of
a branched fiber being the ratio of the cross-section to the
longest branch. In an embodiment, the rod-like structures may
comprise an amphiphathic design to produce a balance between
hydrophobicity and hydrophilicity.
[0080] In an embodiment, fibers suitable for use as colloidal
particles have a length of 0.001 to 100 microns, or from 0.01 to 50
microns, or from 0.1 to 5 microns, of from 0.001 to less than 1
micron, and have a diameter is in the range of 0.001 to 10 microns.
In an embodiment, fibers suitable for use as colloidal particles
comprise an aspect ratio (length/diameter) of from greater than or
equal to about 10, or 20, or 50, up to about 1000.
[0081] Specific examples of colloidal particles, modified or
unmodified, include zinc oxide, iron oxide, copper oxide, titanium
dioxide, aluminum oxide, calcium carbonate, precipitated silica and
fumed silica, as well as mixtures thereof. In an embodiment,
fibers, either modified or unmodified, which may be suitable for
use as hydrolyzable colloidal particles comprise microcrystalline
cellulose (MCC), natural plant fibers, including citrus fibres,
onion fibres, silk and the like. Other examples of fibers suitable
for use as colloidal particles may comprise stearic acid,
polyhydroxybutyrate-valerate, polyvinyl pyrrolidone,
polycaprolactone, their derivatives and copolymers, and other
polymers that can be spun with diameters ranging from 0.001 to
about 30 microns.
[0082] In an embodiment, inorganic fibers suitable for use as
colloidal particles may comprise CaCO.sub.3, CaSO.sub.4, ZnO,
TiO.sub.2, MgO, MgSO.sub.4, Mg(OH).sub.2, Mg.sub.2B.sub.2O.sub.5,
aluminium borate, potassium titanate, barium titanate,
hydroxyapatite, attapulgite, as well as other inorganic crystals
having fiber-like morphology.
[0083] In an embodiment, colloidal particles suitable for use
herein may be modified to produce a contact angle in the range of
between 60.degree. and 120.degree., or between 70.degree. and
110.degree., or between 80.degree. and 100.degree., wherein the
contact angle is the three-phase contact angle at the fibre/first
phase/second phase interface, (e.g., fiber/oil/water
interface).
[0084] In an embodiment, the modification of a fibre can be
achieved by chemical or physical means. The chemical modification
may include esterification or etherification by means of
hydrophobic groups such as stearate, alkoxy groups, and the like as
known to one of skill in the art. Suitable physical modifications
include coating of the fibers with hydrophobic materials, for
example ethylcellulose, hydroxypropyl-cellulose, waxes such as
shellac, carnauba wax, bees wax, and the like, with fatty acids
such as stearic acid, and the like, or combinations thereof. In an
embodiment, colloidal particles may be coating using colloidal
precipitation, e.g., using solvent or temperature change, and the
like, and/or using "decoration" of rod like materials using
hydrophobic nano-particles, for instance silica, as is readily
understood by one having minimal skill in the art.
[0085] In an embodiment, the colloidal particles of the particle
emulsion may comprise hydrolyzable materials, and/or may be
selected to stabilize the particle emulsion for a particular period
of time, a particular set of conditions, and/or the like, and then
subsequently break down destabilizing the emulsion and thus,
destabilizing the particles contained therein. In an embodiment,
the colloidal particles comprise a hydrolyzable material, which may
stable at neutral pH, but which may be acid soluble at a pH below
about 1.5, and/or base soluble at a pH of greater than about
11.
Ostwald Ripening Inhibitor
[0086] In an embodiment, the particle emulsion may further comprise
an Ostwald ripening inhibitor, which may be selected to stabilize
the particle emulsion for a particular period of time, a particular
set of conditions, and/or the like and then subsequently break down
destabilizing the emulsion and thus, destabilizing the particles
contained therein.
[0087] In an embodiment, Ostwald ripening inhibitors may be soluble
or miscible in the disperse oil phase, or may themselves serve as
the disperse oil phase. Ostwald ripening inhibitors have more
affinity for the disperse oil phase than the continuous aqueous
phase and preferably have a log P of 3 or higher. Suitable Ostwald
ripening inhibitors include Ostwald ripening inhibitor solvents
such as vegetable oils, methylated vegetable oils, mineral oils,
liquid hydrocarbon solvents containing from 8 to 20 carbon atoms,
petroleum hydrocarbons wherein 30 to 100 wt. % of the carbon
structures of the hydrocarbons have a carbon number distribution in
the range of 022 to 050 and polymeric stabilizers. Suitable Ostwald
ripening inhibitor solvents may comprise very low solubility,
preferably below 100 ppm at 50.degree. C. in the aqueous phase, in
order to remain in the disperse oil phase and not dissolve in the
continuous aqueous phase.
[0088] In an embodiment, liquid hydrocarbon solvents suitable for
use as Ostwald ripening inhibitors include paraffins, naphthenes
and aromatics either as mixtures or as individual components. In an
embodiment, suitable Ostwald ripening inhibitors comprise
hydrocarbon solvents having greater than 50 wt. % paraffins, or at
least 95 wt. %, or at least 98 wt. %, of the carbon structures of
the hydrocarbon solvents have a carbon number distribution from
C.sub.10 to C.sub.20, and/or comprise hydrocarbon solvents have an
initial boiling point of at least 200.degree. C., or at least
250.degree. C., and a final boiling point of 325.degree. C. or less
at atmospheric pressure.
[0089] In an embodiment, Ostwald ripening inhibitors suitable for
use herein include polymers or oligomers having a molecular weight
of at least 200, or at least 400, and include polyolefins such as
polyallene, polybutadiene, polyisoprene, and poly(substituted
butadienes) such as poly(2-t-butyl-1,3-butadiene),
poly(2-chlorobutadiene), poly(2-chloromethyl butadiene),
polyphenylacetylene, polyethylene, chlorinated polyethylene,
polypropylene, polybutene, polyisobutene, polybutylene oxides, or
copolymers of polybutylene oxides with propylene oxide or ethylene
oxide, polycyclopentylethylene, polycyclohexylethylene,
polyacrylates including polyalkylacrylates and polyarylacrylates,
polymethacrylates including polyalkylmethacrylates and
polyarylmethacrylates, polydisubstituted esters such as
poly(di-n-butylitaconate), and poly(amylfumarate), polyvinylethers
such as poly(butoxyethylene) and poly(benzyloxyethylene),
poly(methyl isopropenyl ketone), polyvinyl chloride, polyvinyl
acetate, polyvinyl carboxylate esters such as polyvinyl propionate,
polyvinyl butyrate, polyvinyl caprylate, polyvinyl laurate,
polyvinyl stearate, polyvinyl benzoate, polystyrene, poly-t-butyl
styrene, poly (substituted styrene), poly(biphenyl ethylene),
poly(1,3-cyclohexadiene), polycyclopentadiene, polyoxypropylene,
polyoxytetramethylene, polycarbonates such as
poly(oxycarbonyloxyhexamethylene), polysiloxanes, in particular,
polydimethyl cyclosiloxanes and organo-soluble substituted
polydimethyl siloxanes such as alkyl, alkoxy, or ester substituted
polydimethylsiloxanes, liquid polysulfides, natural rubber and
hydrochlorinated rubber, ethyi-, butyl- and benzyl-celluloses,
cellulose esters such as cellulose tributyrate, cellulose
tricaprylate and cellulose tristearate and natural resins such as
colophony, copal and shellac, and combinations thereof.
[0090] In an embodiment, Ostwald ripening inhibitors suitable for
use herein include polymers or co-polymers comprising styrene,
alkyl styrenes, isoprene, butenes, butadiene, acrylonitrile, alkyl
acrylates, alkyl methacrylates, vinyl chloride, vinylidene
chloride, vinyl esters of lower carboxylic acids and alpha,
beta-ethylenically unsaturated carboxylic acids and esters
thereof.
[0091] In an embodiment, the Ostwald ripening inhibitor is selected
from the group consisting of polystyrenes, polybutenes, for example
polyisobutenes, polybutadienes, polypropylene glycol,
polyalkyl(meth)acrylate e.g. polyisobutylacrylate or
polyoctadecylmethacrylate, polyvinylesters e.g. polyvinylstearate,
polystyrene/ethyl hexylacrylate copolymer, and polyvinylchloride,
polydimethyl cyclosiloxanes, organic soluble substituted
polydimethyl siloxanes such as alkyl, alkoxy or ester substituted
polydimethylsiloxanes, polybutylene oxides or copolymers of
polybutylene oxides with propylene and/or ethylene oxide, or
combinations thereof.
[0092] In an embodiment, the Ostwald ripening inhibitor is selected
from the group consisting of polypropylene, polyisobutylene,
polyisoprene, copolymers of monoolefins and diolefins,
polyacrylate, polystyrene, polyvinyl acetate, polyurethanes and
polyamides.
[0093] In an embodiment, the Ostwald ripening inhibitor may be used
as a pre-prepared polymer or oligomer. In an alternative
embodiment, the Ostwald ripening inhibitor may be prepared in situ
by polymerization of one or more appropriate monomers within the
non-aqueous phase, after preparation of the dispersion. In an
embodiment, the Ostwald ripening inhibitor may be employed in an
amount of from 0.1 to 20%, preferably from 0.2 to 6% by weight of
the dispersed phase of the particle emulsion.
Treatment Fluid and Method to Produce a Treatment Fluid
[0094] In an embodiment, a method, comprises dispersing a first
liquid phase in a second liquid phase in the presence of a
plurality of colloidal particles under conditions sufficient to
produce a particle emulsion comprising particles of the first
liquid phase dispersed in the continuous second liquid phase, and
comprising at least a portion of the plurality of colloidal
particles adsorbed to a liquid-liquid interface between the first
liquid phase and the second liquid phase; mixing the particle
emulsion in a carrier fluid to produce a treatment fluid; and
circulating the treatment fluid into a wellbore.
[0095] In an embodiment, the method further comprises introducing
Apollonianistic solids into the treatment fluid. In an embodiment,
the method further comprises forming a pack of the solids in the
wellbore. In an embodiment, the pack comprises proppant and at
least one particle size distribution mode comprising particles of
the dispersed first phase. In an embodiment, the pack comprises at
least one particle size distribution mode comprising free colloidal
particles. In an embodiment, the method may further comprise
removing at least a portion of the particles from the pack to form
a permeable proppant pack. In an embodiment, the method further
comprises producing or injecting a fluid through the permeable
proppant pack. In an embodiment, the permeable proppant pack is
disposed in a fracture.
[0096] In an embodiment, the emulsion may be formed within a
treatment fluid, or may be formed externally and added to a
treatment fluid.
[0097] In an embodiment, 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 an embodiment,
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.
[0098] In an embodiment, the aqueous or other liquid phase may have
a specific gravity less than 1. In an embodiment, 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 an embodiment, 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 an
embodiment, 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.
[0099] In an embodiment, the treatment fluid comprising a Pickering
emulsion may be stable, or may be a stabilized treatment slurry.
"Stable" or "stabilized" or similar terms refer to a stabilized
treatment fluid or slurry 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 treatment fluid, and/or the
slurry may generally be regarded as stable over the duration of
expected treatment fluid storage and use conditions, e.g., a
treatment fluid that passes a stability test or an equivalent
thereof. In an embodiment, 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.
[0100] 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.
[0101] In an embodiment, one stability test is referred to herein
as the "8 h@15 Hz/10 d-static treatment fluid 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.
[0102] As used herein, a stabilized treatment fluid may meet at
least one of the following conditions: [0103] (1) the slurry has a
low-shear viscosity equal to or greater than 1 Pa-s (5.11 s.sup.-1,
25.degree. C.); [0104] (2) the slurry has a Herschel-Bulkley
(including Bingham plastic) yield stress equal to or greater than 1
Pa; or [0105] (3) the largest particle mode in the slurry has a
static settling rate less than 0.01 mm/hr; or [0106] (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 [0107] (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 [0108] (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
[0109] (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.
[0110] In an embodiment, 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% greater than 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.
[0111] In an embodiment, the treatment 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) hydrolyzable 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. 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.
[0112] Decreasing the density difference between the particle and
the carrier fluid may be done in an embodiment 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 an embodiment 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
an embodiment 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.
[0113] In an embodiment, yield stress fluids, and also fluids
having a high low-shear viscosity may be used to retard the motion
of the carrier fluid and thus retard particle settling. The
gravitational stress exerted by the particle at rest on the fluid
beneath it must generally exceed the yield stress of the fluid to
initiate fluid flow and thus settling onset. 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.
[0114] Increasing carrier fluid viscosity in a Newtonian fluid also
proportionally increases the resistance of the carrier fluid
motion. In an embodiment, 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 an embodiment, 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 an embodiment, the fluid phase viscosity
ranges from any lower limit to any higher upper limit.
[0115] In an embodiment, an agent may both viscosify and impart
yield stress characteristics, and in further an embodiment may also
function as a friction reducer to reduce friction pressure losses
in pumping the treatment fluid. In an embodiment, 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. 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 an embodiment, clean up can be effected
using a breaker(s). In an embodiment, 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 an
embodiment, 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.
[0116] 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 an embodiment, the
treatment fluid has a lower limit of apparent dynamic viscosity,
determined at 170 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
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 an
embodiment, the treatment fluid viscosity ranges from any lower
limit to any higher upper limit.
[0117] In an embodiment, 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.
[0118] In an embodiment, the 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 an embodiment 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
treatment fluid.
[0119] FIG. 2 shows a data set 200 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
202 indicated with a triangle were values that had free water in
the slurry, data points 204 indicated with a circle were slurriable
fluids that were mixable without excessive free water, and data
points 206 indicated with a diamond were not easily mixable
liquid-solid mixtures. The data set 200 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 200 that the compositions can be defined approximately
into a non-mixable region 210, a slurriable region 212, and a
settling region 214.
[0120] FIG. 2 shows the useful range of SVF and PVF for slurries in
an embodiment without gelling agents. In an embodiment, 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 an
embodiment 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 an embodiment 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 an
embodiment allows fluids otherwise in the settling area 214 an
embodiment (where SVF/PVF is less than or equal to about
1-2.1*(PVF-0.72)) to also be useful as an treatment fluid 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.
[0121] Introducing high-aspect ratio particles into the treatment
fluid, e.g., particles having an aspect ratio of at least 6,
represents additional or alternative an embodiment 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,
US20080196896, which are hereby incorporated herein by reference.
In an embodiment, introducing ciliated or coated proppant into the
treatment fluid may stabilize or help stabilize the treatment
fluid.
[0122] 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.
[0123] In some additional or alternative embodiments, the treatment
fluid according the instant disclosure 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 an
embodiment by the flow of the treatment fluid through a relatively
small slot orifice with respect to the maximum diameter of the
largest particle mode of the treatment fluid, 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 treatment fluid 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.
[0124] In an embodiment, the flowability of the treatment fluid
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.
[0125] 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 an embodiment, the treatment fluid 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.
[0126] Because of the relatively low water content (high SVF) of
some embodiments of the treatment fluid, fluid loss 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 may not be
optimized for creating fractures in the formation.
[0127] In an embodiment of the treatment fluid comprising a
Pickering emulsion 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 an embodiment 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 an embodiment, the treatment fluid 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.
[0128] In an embodiment herein, the treatment fluid 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).
[0129] In an embodiment the treatment fluid comprising a Pickering
emulsion may also have 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 an embodiment 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 an
embodiment 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 an embodiment 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 an embodiment 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.
[0130] The unique low to no fluid loss property allows the
treatment fluid to be pumped at a low rate or pumping stopped
(static) with a low risk of screen out. In an embodiment, the low
fluid loss characteristic may be obtained by including a leak-off
control agent comprising the colloidal particles, and/or one or
more additional fluid loss control agents, also referred to in the
art as leakoff control agents.
[0131] 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 an
embodiment, the leak-off control agent comprises a reactive solid,
e.g., a hydrolyzable 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 an embodiment, 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 an embodiment, 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.
[0132] The treatment fluid may additionally or alternatively
include, without limitation, friction reducers, clay stabilizers,
biocides, crosslinkers, 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.
[0133] In an embodiment herein, the treatment fluid may be prepared
by combining the proppant if present, and other particles including
the Pickering emulsion particles, 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 an embodiment, the base fluid
may be prepared from a fluid comprising the Pickering emulsion, the
carrier liquid and other additives, and then the base fluid
combined with the proppant.
[0134] The treatment fluid may be prepared on location, e.g., at
the wellsite when and as needed using conventional treatment fluid
blending equipment.
[0135] FIG. 3 shows a wellsite equipment configuration 300 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 310A, 310B. Water tanks
312A, 312B, 312C, 312D are arranged along one side of the operation
site. Hopper 314 receives sand from the sand trailers 310A, 310B
and distributes it into the mixer truck 316. Blender 318 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 331. The final mixed and blended
slurry, also called frac fluid, is then transferred to the pump
trucks 322A, 322B, 322C, 322D, and routed at treatment pressure
through treating line 334 to rig 335, 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.
[0136] In an embodiment herein, for example in gravel packing,
fracturing and frac-and-pack operations, the treatment fluid
comprises a Pickering emulsion and a 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 an embodiment, Vfluid/Vprop is
equal to or less than 2.5. In an embodiment, Vfluid/Vprop is equal
to or less than 2. In an embodiment, Vfluid/Vprop is equal to or
less than 1.5. In an embodiment, Vfluid/Vprop is equal to or less
than 1.25. In an embodiment, Vfluid/Vprop is equal to or less than
1. In an embodiment, Vfluid/Vprop is equal to or less than 0.75. In
an embodiment, Vfluid/Vprop is equal to or less than 0.7. In an
embodiment, Vfluid/Vprop is equal to or less than 0.6. In an
embodiment, Vfluid/Vprop is equal to or less than 0.5. In an
embodiment, Vfluid/Vprop is equal to or less than 0.4. In an
embodiment, Vfluid/Vprop is equal to or less than 0.35. In an
embodiment, Vfluid/Vprop is equal to or less than 0.3. In an
embodiment, Vfluid/Vprop is equal to or less than 0.25. In an
embodiment, Vfluid/Vprop is equal to or less than 0.2. In an
embodiment, Vfluid/Vprop is equal to or less than 0.1. In an
embodiment, Vfluid/Vprop may be sufficiently high such that the
treatment fluid is flowable. In an embodiment, the ratio
V.sub.fluid/V.sub.prop 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.
[0137] Nota bene, the treatment fluid may optionally comprise
subproppant particles, which may include the Pickering emulsion, 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
treatment fluid 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 an embodiment, 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 an embodiment (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 an embodiment reference to the concentration
by weight of low concentration additives other than proppant, e.g.,
1 ppt=0.12 g/L.
[0138] In an embodiment, 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 an embodiment 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 an embodiment 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 an
embodiment 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 an embodiment 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 an embodiment 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 an
embodiment 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 an embodiment 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 an embodiment 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 an
embodiment where the proppant has a specific gravity of 2.65).
[0139] As used herein, in an embodiment, "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 an embodiment, 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 an embodiment, 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.
[0140] In an embodiment, 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 enter the aquifers and other 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.
[0141] In an embodiment 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 an embodiment 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. An
embodiment 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 an
embodiment, the solids pack obtained from a treatment fluid with
multimodal solids can retain a larger proportion of water than
conventional proppant packs, further reducing the amount of water
flowback. In an embodiment, 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.
[0142] 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
comprising a Pickering emulsion, 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 an embodiment
may comprise both proppant and one or more sub-proppant particle
modes. In an embodiment, the continuous fluid phase is a liquid
phase.
[0143] In an embodiment, the treatment fluid is prepared by
combining the proppant and a fluid phase comprising the Pickering
emulsion, 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 an embodiment, 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 lbf/ft.sup.2). In an embodiment, 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).
[0144] In an embodiment, e.g., for delivery of a fracturing stage,
the treatment fluid 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).
[0145] In an embodiment, 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.
[0146] In an embodiment, e.g., a front-end stage treatment fluid,
the slurry comprises a stabilized solids mixture comprising a
Pickering emulsion and a particulated leakoff control system (which
may include the colloidal particles, and may optionally include
other solid and/or liquid particles, e.g., submicron particles,
colloids, micelles, PLA dispersions, latex systems, and the like)
and a solids volume fraction (SVF) of at least 0.4.
[0147] In an embodiment, e.g., a pad stage treatment fluid, 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.
[0148] In an embodiment, e.g., a flush stage treatment fluid, the
slurry comprises a proppant-free slurry comprising a stabilized
solids mixture comprising a Pickering emulsion and a particulated
leakoff control system having a solids volume fraction (SVF) of at
least 0.4. In an embodiment, 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 an embodiment, 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).
[0149] In an embodiment, the proppant stage comprises a continuous
single injection of spacers. In an embodiment the treatment fluid
comprises a total proppant volume injected into the wellbore or to
be injected into the wellbore of at least 800 liters.
[0150] In an embodiment, the total proppant volume is at least 1600
liters. In an embodiment, the total proppant volume is at least
[0151] In an embodiment, the total proppant volume is at least
80,000 liters. In an embodiment, 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.
[0152] Sometimes it is 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 an embodiment herein, the treatment fluid is
stabilized and the operator can decide to resume and/or complete
the fracture operation, or to circulate the treatment fluid (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.
[0153] Due to the stability of the treatment fluid in an embodiment
herein, the proppant will remain suspended and the fluid will
retain its fracturing properties during the time the pumping is
interrupted. In an embodiment 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 comprising the Pickering emulsion to form a
proppant-containing treatment fluid, stabilizing the
proppant-containing treatment fluid, pumping the treatment fluid,
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 treatment fluid 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 an embodiment the treatment fluid
will itself suspend and convey all the proppant out of the wellbore
with high efficiency. In an embodiment, 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.
[0154] In an embodiment, the treatment provides production-related
features resulting from a low water content and/or the presence of
a Pickering emulsion 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.
[0155] Very low water slurries and water free slurries according to
an embodiment disclosed herein offer a pathway to significantly
reduce water infiltration and the collateral formation damage that
may occur. Low water treatment fluids minimize water infiltration
relative to slick water fracture treatments by two mechanisms.
First, the water content in the treatment fluid can be less than
about 40% of slickwater per volume of respective treatment fluid,
and the treatment fluid can provide in an embodiment 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
treatment fluid, in an embodiment including subproppant particles
comprising a Pickering emulsion, retains more water than
conventional proppant packs so that less water is released from the
treatment fluid into the formation.
[0156] 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 an embodiment 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 an embodiment 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.
[0157] 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 treatment fluid in an embodiment 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.
[0158] 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 an embodiment of a treatment fluid
comprising a Pickering emulsion is that it will dehydrate and
become an immobile mass (plug) upon losing more than 25% of the
water it is formulated with. As a treatment fluid in an embodiment
only contains up to 50% water by volume, then it will only require
a loss of a total of 12.5% of the 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 an embodiment
only contains up to 40% water by volume, requiring a loss of a
total of 10% of the 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.
[0159] 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 an embodiment 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 an
embodiment 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.
[0160] In an embodiment, 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 an embodiment 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.
[0161] In an embodiment, 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 a treatment fluid comprising a Pickering
emulsion, 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 an embodiment, 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.
[0162] Various jetting and jet cutting operations in an embodiment
are significantly improved by the non-settling and solids carrying
abilities of the treatment fluid. Jet perforating and jet slotting
are an embodiment for the treatment fluid, wherein the proppant is
replaced with an abrasive or erosive particle. Multi-zone
fracturing systems using a locating sleeve/polished bore and jet
cut opening are an embodiment.
[0163] Drilling cuttings transport and cuttings stability during
tripping are also improved in an embodiment. The treatment fluid
can act to either fracture the formation or bridge off cracks,
depending on the exact mixture used. The treatment fluid can
provide an extreme ability to limit fluid losses to the formation,
a very significant advantage. Minimizing the amount of liquid will
make oil based muds much more economically attractive.
[0164] The modification of producing formations using explosives
and/or propellant devices in an embodiment is improved by the
ability of the treatment fluid to move after standing stationary
and also by its density and stability.
[0165] Zonal isolations operations in an embodiment are improved by
specific treatment fluid formulations comprising a Pickering
emulsion, optimized for leakoff control and/or bridging abilities.
Relatively small quantities of the treatment fluid radically
improve the sealing ability of mechanical and inflatable packers by
filling and bridging off gaps. Permanent isolation of zones is
achieved in an embodiment by bullheading low permeability versions
of the treatment fluid into water producing formations or other
formations desired to be isolated. Isolation in an embodiment is
improved by using a setting formulation of the treatment fluid, but
non-setting formulations can provide very effective permanent
isolation. Temporary isolation may be delivered in an embodiment by
using degradable materials to convert a non-permeable pack into a
permeable pack after a period of time.
[0166] The pressure containing ability and ease of
placement/removal of sand plugs in an embodiment are significantly
improved using appropriate treatment fluid formulations comprising
a Pickering emulsion 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 an
embodiment; a solid sand pack may be readily re-fluidized and
circulated out, unlike conventional sand plugs.
[0167] In an embodiment, plug and abandon work may be improved
using CRETE cementing formulations in the treatment fluid
comprising a Pickering emulsion, and also by placing
bridging/leakoff controlling treatment fluid formulations below
and/or above cement plugs to provide a seal repairing material. The
ability of the treatment fluid to re-fluidize after long periods of
immobilization facilitates this embodiment. 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, and
are commercially available from Schlumberger.
[0168] This treatment fluid, in an embodiment finds application in
pipeline cleaning to remove methane hydrates due to its carrying
capacity and its ability to resume motion.
[0169] Accordingly, the present disclosure provides the following
embodiments: [0170] 1. A treatment fluid, comprising: [0171] a
plurality of particles comprising an Apollonianistic particle size
distribution comprising particles of a Pickering emulsion,
comprising particles of a first liquid phase dispersed in a
continuous second liquid phase, and a plurality of colloidal
particles, at least a portion of the colloidal particles adsorbed
to a liquid-liquid interface between the first liquid phase and the
second liquid phase. [0172] 2. The treatment fluid of embodiment 1,
wherein at least a portion of the plurality of colloidal particles
is freely dispersed in the second liquid phase, and wherein the
freely dispersed colloidal particles comprise at least one particle
size distribution mode of the Apollonianistic particle size
distribution. [0173] 3. The treatment fluid of embodiment 1 or 2,
wherein the colloidal particles have a particle size distribution
mode from 0.005 to 100 microns. [0174] 4. The treatment fluid of
any one of embodiments 1 to 3, wherein the colloidal particles
comprise an aspect ratio from 1.1 to about 1000. [0175] 5. The
treatment fluid of any one of embodiments 1 to 4, wherein the
colloidal particles comprise a contact angle of about 60.degree. to
about 120.degree., when determined at a boundary of the colloidal
particle/first liquid phase/second liquid phase interface. [0176]
6. The treatment fluid of any one of embodiments 1 to 5, wherein
the colloidal particles have an average length from about 0.001
microns to about 100 microns. [0177] 7. The treatment fluid of any
one of embodiments 1 to 6, wherein the colloidal particles comprise
fibers having an aspect ratio from about 10 to about 1000. [0178]
8. The treatment fluid of any one of embodiments 1 to 7, wherein
the colloidal particles have been surface modified to comprise a
contact angle of about 20.degree. to about 150.degree., or about
60.degree. to about 120.degree., when determined at a boundary of
the colloidal particle/first liquid phase/second liquid phase
interface. [0179] 9. The treatment fluid of any one of embodiments
1 to 8, further comprising at least one Ostwald ripening inhibitor
which is soluble or miscible in the first phase or which itself
serves as the first phase. [0180] 10. The treatment fluid of any
one of embodiments 1 to 9, further comprising from about 1 to 20
parts per 100 parts by weight of one or more of a dispersant, a
surfactant, a viscosifier, or a defoamer. [0181] 11. The treatment
fluid of any one of embodiments 1 to 10, wherein the colloidal
particles are hydrolyzable. [0182] 12. A treatment fluid,
comprising: [0183] a Pickering emulsion comprising particles of a
first liquid phase dispersed in a continuous second liquid phase,
and a plurality of hydrolyzable colloidal particles, at least a
portion of which are adsorbed to a liquid-liquid interface between
the first liquid phase and the second liquid phase. [0184] 13. The
treatment fluid of embodiment 12, wherein the hydrolyzable
colloidal particles comprise wax, C.sub.1-C.sub.20 aliphatic
polyester, polylactic acid, polyglycolic acid, polycaprolactone,
polyhydroxybutyrate, polyhydroxybutyrate-valerate copolymer,
C.sub.20 aliphatic polycarbonate, polyphosphazene, polysaccharide,
dextran, cellulose, chitin, chitosan, protein, polyamino acid,
polyethylene oxide, microcrystalline cellulose, natural plant
fibers, silk, stearic acid, polyvinyl pyrrolidone, calcium
carbonate, calcium sulfate, zinc oxide, titanium dioxide, magnesium
oxide, magnesium sulfate, magnesium hydroxide, magnesium borate,
aluminum borate, potassium titanate, barium titanate,
hydroxyapatite, attapulgite, iron oxides, copper oxides, aluminum
oxide, precipitated silica, fumed silica, or a combination thereof.
[0185] 14. The treatment fluid of embodiment 12 or 13, wherein the
hydrolyzable colloidal particles comprise fibers having an aspect
ratio from about 10 to about 1000. [0186] 15. A method, comprising:
[0187] dispersing a first liquid phase in a second liquid phase in
the presence of a plurality of colloidal particles under conditions
sufficient to produce a Pickering emulsion comprising a plurality
of emulsion particles comprising the first liquid phase dispersed
in the continuous second liquid phase, and comprising at least a
portion of the plurality of colloidal particles adsorbed to a
liquid-liquid interface between the first liquid phase and the
second liquid phase; [0188] mixing the emulsion in a carrier fluid
to produce a treatment fluid comprising a plurality of particles
having an Apollonianistic particle size distribution; and [0189]
circulating the treatment fluid into a wellbore. [0190] 16. The
method of embodiment 15, further comprising forming a pack of the
solids in the wellbore, wherein the pack comprises at least one
particle size distribution mode comprising the emulsion particles.
[0191] 17. The method of embodiment 15 or 16, wherein at least a
portion of the plurality of colloidal particles is freely dispersed
in the treatment fluid, and wherein the pack comprises at least one
particle size distribution mode comprising the freely dispersed
colloidal particles. [0192] 18. The method of any one of
embodiments 15 to 17, further comprising removing at least a
portion of the emulsion particles from the pack to form a permeable
proppant pack. [0193] 19. The method of embodiment 18, further
comprising producing or injecting a fluid through the permeable
proppant pack. [0194] 20. The method of embodiment 19, wherein the
permeable proppant pack is disposed in a fracture. [0195] 21. A
method comprising: [0196] dispersing a first liquid phase in a
second liquid phase in the presence of a plurality of hydrolyzable
colloidal particles under conditions sufficient to produce a
Pickering emulsion comprising a plurality of emulsion particles
comprising the first liquid phase dispersed in the continuous
second liquid phase, and comprising at least a portion of the
plurality of hydrolyzable colloidal particles adsorbed to a
liquid-liquid interface between the first liquid phase and the
second liquid phase; [0197] mixing the emulsion in a carrier fluid
to produce a treatment fluid; and [0198] circulating the treatment
fluid into a wellbore. [0199] 22. The method of embodiment 21,
wherein the hydrolyzable colloidal particles comprise wax,
C.sub.1-C.sub.20 aliphatic polyester, polylactic acid, polyglycolic
acid, polycaprolactone, polyhydroxybutyrate,
polyhydroxybutyrate-valerate copolymer, C.sub.1-C.sub.20 aliphatic
polycarbonate, polyphosphazene, polysaccharide, dextran, cellulose,
chitin, chitosan, protein, polyamino acid, polyethylene oxide,
microcrystalline cellulose, natural plant fibers, silk, stearic
acid, polyvinyl pyrrolidone, calcium carbonate, calcium sulfate,
zinc oxide, titanium dioxide, magnesium oxide, magnesium sulfate,
magnesium hydroxide, magnesium borate, aluminum borate, potassium
titanate, barium titanate, hydroxyapatite, attapulgite, iron
oxides, copper oxides, aluminum oxide, precipitated silica, fumed
silica, or a combination thereof. [0200] 23. The method of
embodiment 21 or 22, wherein the hydrolyzable colloidal particles
comprise fibers having an aspect ratio from about 10 to about 1000.
[0201] 24. A treatment fluid produced according to any one of
embodiments 15 to 17, or 21 to 23. [0202] 25. A treatment fluid
according to any one of embodiments 1 to 14, comprising less than
about 0.1 wt % of a surfactant. [0203] 26. A treatment fluid
according to any one of embodiments 1 to 14, comprising at least
one of the following stability indicia: [0204] (1) an SVF of at
least 0.4 up to SVF=PVF; [0205] (2) a low-shear viscosity of at
least 1 Pa-s (5.11 s.sup.-1, 25.degree. C.); [0206] (3) a yield
stress (as determined herein) of at least 1 Pa; [0207] (4) an
apparent viscosity of at least 50 mPa-s (170 s.sup.-1, 25.degree.
C.); [0208] (5) a multimodal solids phase; [0209] (6) a solids
phase having a PVF greater than 0.7; [0210] (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; [0211] (8) hydrolyzable colloidal particles; [0212]
(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); [0213] (10) particles having an aspect ratio of at least
6; [0214] (11) ciliated or coated proppant; and [0215] (12)
combinations thereof.
[0216] 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. Those skilled in
the art will appreciate that many modifications are possible in the
example an embodiment 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.
[0217] 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