U.S. patent application number 13/803352 was filed with the patent office on 2014-06-05 for stabilized fluids in well treatment.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to James Ernest Brown, Matthew J. Miller, John R. Whitsitt.
Application Number | 20140151043 13/803352 |
Document ID | / |
Family ID | 50824302 |
Filed Date | 2014-06-05 |
United States Patent
Application |
20140151043 |
Kind Code |
A1 |
Miller; Matthew J. ; et
al. |
June 5, 2014 |
STABILIZED FLUIDS IN WELL TREATMENT
Abstract
Using stabilized fluids in multistage well treatment is
disclosed. Also disclosed are methods, fluids, equipment and/or
systems for treating a subterranean formation penetrated by a
wellbore, relating to a stabilized treatment slurry.
Inventors: |
Miller; Matthew J.; (Katy,
TX) ; Whitsitt; John R.; (Houston, TX) ;
Brown; James Ernest; (Fort Collins, CO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
TECHNOLOGY CORPORATION; SCHLUMBERGER |
|
|
US |
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
50824302 |
Appl. No.: |
13/803352 |
Filed: |
March 14, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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61732732 |
Dec 3, 2012 |
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Current U.S.
Class: |
166/285 ;
166/281 |
Current CPC
Class: |
E21B 47/13 20200501;
E21B 43/267 20130101; E21B 34/14 20130101; E21B 43/26 20130101 |
Class at
Publication: |
166/285 ;
166/281 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 43/267 20060101 E21B043/267 |
Claims
1. A method, comprising: placing a downhole completion staging
system tool in a wellbore adjacent a subterranean formation;
operating the downhole completion staging system tool to establish
one or more passages for fluid communication between the wellbore
and the subterranean formation in a plurality of wellbore stages
spaced along the wellbore; isolating one of the wellbore stages for
treatment; injecting a stabilized slurry treatment fluid through
the wellbore and the one or more passages of the isolated wellbore
stage into the subterranean formation to place proppant in a
fracture in the subterranean formation; and repeating the isolation
and proppant placement for one or more additional stages.
2. The method of claim 1, wherein the placement of the downhole
completion staging system tool is tethered to a string.
3. The method of claim 1, wherein the downhole completion staging
system tool is translated within the wellbore using the stabilized
slurry treatment fluid as a transport medium.
4. The method of claim 1, wherein the downhole completion staging
system tool comprises a wireline tool string comprising a blanking
plug and perforating guns, and further comprising setting the
blanking plug in the wellbore, placing one or more perforation
clusters above the blanking plug, and recovering the wireline tool
string to the surface, wherein the stabilized slurry treatment
fluid is circulated through the wellbore into the formation to
create the fracture, place the proppant or a combination
thereof.
5. The method of claim 1, wherein the downhole completion staging
system tool comprises a pipe or coiled tubing string comprising a
jetting assembly, and further comprising placing the jetting
assembly in the wellbore, closing an annulus around the string,
circulating abrasive materials down the string through the jetting
assembly to perforate a wellbore casing, wherein the stabilized
slurry treatment fluid is circulated through the annulus,
perforations and into the formation to create the fracture, place
the proppant or a combination thereof.
6. The method of claim 1, further comprising placing a production
liner in the wellbore wherein the production liner is fitted with a
plurality of sliding sleeves in the closed position, and inserting
a sleeve-shifting device into a capture feature on the downhole
completion staging system tool to open a fracturing port, wherein
the stabilized slurry treatment fluid is circulated through the
fracturing port and into the formation to create the fracture,
place the proppant or a combination thereof.
7. The method of claim 1, further comprising forming a plug between
at least two stages.
8. The method of claim 7, wherein the plug is formed from a slurry
treatment fluid and further comprising re-slurrying the plug
following completion of the proppant placement for one stage to
access another one of the one or more additional stages for a
subsequent isolation and proppant placement for the additional one
of the one or more stages.
9. The method of claim 1, wherein stabilized slurry treatment fluid
from one stage is circulated in the wellbore to another stage to
create the fracture, place the proppant or a combination
thereof.
10. The method of claim 1, further comprising circulating another
stabilized slurry treatment fluid through the wellbore between
stages to flush debris from the wellbore following completion of
one stage and prior to initiation of a serial stage, wherein the
flushing slurry treatment fluid may be the same or different
treatment fluid with respect to the proppant placement treatment
fluid of either or both of the immediately preceding or immediately
subsequent stages.
11. The method of claim 1, wherein the stabilized slurry treatment
fluid comprises a viscosity less than 300 mPa-s (170 s.sup.-1,
25.degree. 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).
12. The method of claim 1, wherein the stabilized slurry treatment
fluid comprises 0.36 L or more of proppant volume per liter of
proppant-containing treatment fluid, a viscosity less than 300
mPa-s (170 s.sup.-1, 25.degree. C.), solids having a packed volume
fraction (PVF) greater than 0.6 and a slurry solids volume fraction
(SVF) greater than the PVF.
13. The method of claim 1, further comprising: stopping circulation
of the stabilized slurry treatment fluid to thereby strand the
treatment fluid in the wellbore without solids settling; and
thereafter resuming circulation of the treatment fluid.
14. The method of claim 1, further comprising stabilizing a
treatment fluid to form the stabilized treatment slurry fluid
meeting at least one of the following conditions: (1) the slurry
has a low-shear viscosity equal to or greater than 1 Pa-s (5.11
s.sup.-1, 25.degree. C.); (2) the slurry has a Herschel-Buckley
(including Bingham plastic) yield stress (as determined in the
manner described herein) equal to or greater than 1 Pa; or (3) the
largest particle mode in the slurry has a static settling rate less
than 0.01 mm/hr; or (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
(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 (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 (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.
15. The method of claim 14, wherein: 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.
16. The method of claim 14, wherein the stabilized treatment slurry
is formed by at least one of: (1) introducing sufficient particles
into the slurry or treatment fluid to increase the SVF of the
treatment fluid to at least 0.4; (2) increasing a low-shear
viscosity of the slurry or treatment fluid to at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.); (3) increasing a yield stress of the
slurry or treatment fluid to at least 1 Pa; (4) increasing apparent
viscosity of the slurry or treatment fluid to at least 50 mPa-s
(170 s.sup.-1, 25.degree. C.); (5) introducing a multimodal solids
phase into the slurry or treatment fluid; (6) introducing a solids
phase having a PVF greater than 0.7 into the slurry or treatment
fluid; (7) introducing into the slurry or treatment fluid a
viscosifier selected from viscoelastic surfactants, e.g., in an
amount ranging from 0.01 up to 7.2 g/L (60 ppt), and hydratable
gelling agents, e.g., in an amount ranging from 0.01 up to 4.8 g/L
(40 ppt) based on the volume of fluid phase; (8) introducing
colloidal particles into the slurry or treatment fluid; (9)
reducing a particle-fluid density delta to less than 1.6 g/mL
(e.g., introducing particles having a specific gravity less than
2.65 g/mL, carrier fluid having a density greater than 1.05 g/mL or
a combination thereof); (10) introducing particles into the slurry
or treatment fluid having an aspect ratio of at least 6; (11)
introducing ciliated or coated proppant into slurry or treatment
fluid; and (12) combinations thereof.
17. A method, comprising: placing a downhole completion staging
tool in a wellbore adjacent a subterranean formation; operating the
downhole completion staging tool to establish one or more passages
for fluid communication between the wellbore and the subterranean
formation in a plurality of wellbore stages spaced along the
wellbore; isolating one or more of the wellbore stages for
treatment; isolating one or more of the wellbore stages for
treatment; injecting a treatment fluid through the wellbore and the
one or more passages of the isolated wellbore stage into the
subterranean formation to place proppant in a fracture in the
subterranean formation; circulating a stabilized slurry treatment
fluid through the isolated wellbore stage to facilitate removal of
proppant from the wellbore stage; and repeating the isolation,
proppant placement and slurry treatment fluid circulation for one
or more additional stages.
18. The method of claim 17, further comprising stabilizing a
treatment fluid to form the stabilized treatment slurry fluid
meeting at least one of the following conditions: (1) the slurry
has a low-shear viscosity equal to or greater than 1 Pa-s (5.11
s.sup.-1, 25.degree. C.); (2) the slurry has a Herschel-Buckley
(including Bingham plastic) yield stress (as determined in the
manner described herein) equal to or greater than 1 Pa; or (3) the
largest particle mode in the slurry has a static settling rate less
than 0.01 mm/hr; or (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
(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 (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 (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.
19. The method of claim 17, wherein the stabilized treatment slurry
is formed by at least one of: (1) introducing sufficient particles
into the slurry or treatment fluid to increase the SVF of the
treatment fluid to at least 0.4; (2) increasing a low-shear
viscosity of the slurry or treatment fluid to at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.); (3) increasing a yield stress of the
slurry or treatment fluid to at least 1 Pa; (4) increasing apparent
viscosity of the slurry or treatment fluid to at least 50 mPa-s
(170 s.sup.-1, 25.degree. C.); (5) introducing a multimodal solids
phase into the slurry or treatment fluid; (6) introducing a solids
phase having a PVF greater than 0.7 into the slurry or treatment
fluid; (7) introducing into the slurry or treatment fluid a
viscosifier selected from viscoelastic surfactants, e.g., in an
amount ranging from 0.01 up to 7.2 g/L (60 ppt), and hydratable
gelling agents, e.g., in an amount ranging from 0.01 up to 4.8 g/L
(40 ppt) based on the volume of fluid phase; (8) introducing
colloidal particles into the slurry or treatment fluid; (9)
reducing a particle-fluid density delta to less than 1.6 g/mL
(e.g., introducing particles having a specific gravity less than
2.65 g/mL, carrier fluid having a density greater than 1.05 g/mL or
a combination thereof); (10) introducing particles into the slurry
or treatment fluid having an aspect ratio of at least 6; (11)
introducing ciliated or coated proppant into slurry or treatment
fluid; and (12) combinations thereof.
20. A method, comprising: placing a downhole completion staging
tool in a wellbore adjacent a subterranean formation; operating the
downhole completion staging tool to establish one or more passages
for fluid communication between the wellbore and the subterranean
formation in a plurality of wellbore stages spaced along the
wellbore; injecting a treatment fluid through the wellbore and the
one or more passages into the subterranean formation to place
proppant in a fracture in the subterranean formation; moving the
downhole completion staging tool away from the one or more passages
either before, during or after the injection without removing the
downhole completion staging tool from the wellbore; deploying a
diversion agent to block further flow through the one or more
passages; circulating a stabilized slurry treatment fluid through
the wellbore as the injected treatment fluid or as a flush to
facilitate removal of proppant from the wellbore; and repeating the
downhole completion staging tool placement and operation, proppant
placement, downhole completion staging tool movement and stabilized
slurry treatment circulation for one or more additional stages.
Description
RELATED APPLICATION DATA
[0001] The current application claims the benefit of U.S.
provisional application Ser. No. 61/732,732, filed on Dec. 3, 2012,
titled "Well Treatment Methods And Systems", the entire content of
which is incorporated herein by reference.
BACKGROUND
[0002] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0003] In wells employing multistage hydraulic fracturing stage
tools, a fracturing port is usually opened by sliding a sleeve,
permitting injected fracturing fluids to escape the wellbore and
create a fracture in the surrounding formation. The device that
shifts the sleeve is a ball, a dart, or even a length of tubing
inserted into the wellbore. The device travels (or is inserted) up
to the point where the device is captured by a capture feature on
the stage tool, such as a collet, lever, cavity, etc., and further
device motion pushes the sleeve open. Some representative
multistage hydraulic fracturing stage tools are disclosed in U.S.
Pat. No. 7,387,165, U.S. Pat. No. 7,322,417, U.S. Pat. No.
7,377,321, US20070107908, US20070044958, US20100209288, U.S. Pat.
No. 7,387,165, US2009/0084553, U.S. Pat. No. 7,108,067, U.S. Pat.
No. 7,431,091, U.S. Pat. No. 6,907,936, U.S. Pat. No. 7,543,634,
U.S. Pat. No. 7,134,505, U.S. Pat. No. 7,021,384, U.S. Pat. No.
7,353,878, U.S. Pat. No. 7,267,172, U.S. Pat. No. 7,681,645, U.S.
Pat. No. 7,703,510, U.S. Pat. No. 7,784,543, U.S. Pat. No.
7,628,210, WO2012083047, U.S. Pat. No. 7,066,265, U.S. Pat. No.
7,168,494, U.S. Pat. No. 7,353,879, U.S. Pat. No. 7,093,664, U.S.
Pat. No. 7,210,533, U.S. Pat. No. 7,343,975, U.S. Pat. No.
7,431,090, U.S. Pat. No. 7,571,766, U.S. Pat. No. 8,104,539, and
US2010/0044041, U.S. Pat. No. 8,066,069, U.S. Pat. No. 6,866,100,
U.S. Pat. No. 8,201,631; US20120090847; US20110198082;
US20080264636, which are hereby incorporated herein by
reference.
[0004] The major complication that reduces the reliable operation
of these sliding sleeves is the accumulation of debris in the
wellbore. That debris can pile up in front of the device and
prevent it from reaching the "capture feature" of the stage tool.
The debris can lodge in and around the capture feature and jam the
sliding sleeve. Eliminating wellbore debris would eliminate those
failure mechanisms and improve the reliability substantially of
sliding sleeve systems.
[0005] In many instances, the debris is proppant that has dropped
out of the fracturing fluid. Proppant drop out happens for a
variety of reasons, for example: A) the proppant suspension
characteristics may be poor leading to proppant drop out under all
hydrodynamic conditions, B) an operational problem may result in a
shut down for enough time for proppant to settle out of suspension
of a slurry, even one that otherwise has good slurry suspension
under normal operating conditions, C) the proppant suspension
characteristics are mediocre, but due to the very long horizontal
well length, and the fact that the entire vertical span of the
horizontal portion of the well is only several inches, some
proppant dropout occurs during the long transit time of the slurry
from the heel of the well to the reservoir injection point.
[0006] There is a long-felt need for a staging system with more
precise operational control and significantly reduced water usage,
i.e., as a corollary, a system that will operate at lower transport
velocities and at higher proppant:water ratios. There is also a
need to inhibit and minimize adverse effects from accumulation of
debris that may otherwise interfere with the reliable operation of
mechanical equipment in multistage hydraulic fracturing stage
tools.
SUMMARY
[0007] In some embodiments herein, the treatments, treatment
fluids, systems, equipment, methods, and the like employ a
stabilized treatment slurry (STS) wherein the solid phase, which
may include proppant, is at least temporarily inhibited from
gravitational settling in the fluid phase. In some embodiments, the
STS may have an at least temporarily controlled rheology, such as,
for example, viscosity, leakoff or yield strength, or other
physical property, such as, for example, specific gravity, solids
volume fraction (SVF), or the like. In some embodiments, the solids
phase of the STS may have an at least temporarily controlled
property, such as, for example, particle size distribution
(including modality(ies)), packed volume fraction (PVF),
density(ies), aspect ratio(s), sphericity(ies), roundness(es) (or
angularity(ies)), strength(s), permeability(ies), solubility(ies),
reactivity(ies), etc.
[0008] In some embodiments, multistage completion methods or
systems employ a stabilized treatment slurry (STS) wherein the
solid phase, which may include proppant, is inhibited from
gravitational settling in the fluid phase. In some embodiments
herein, the multistage completion methods may include circulation
of a stabilized slurry treatment fluid in the wellbore to
facilitate removal of debris.
[0009] In some embodiments, a method comprises: placing a downhole
completion staging system or tool in a wellbore adjacent a
subterranean formation; operating the downhole completion staging
system tool to establish one or more passages for fluid
communication between the wellbore and the subterranean formation
in a plurality of wellbore stages spaced along the wellbore;
isolating one of the wellbore stages for treatment; injecting a
stabilized treatment slurry (STS) through the wellbore and the one
or more passages of the isolated wellbore stage into the
subterranean formation to place proppant in a fracture in the
subterranean formation; and repeating the isolation and proppant
placement for one or more additional stages.
[0010] In some embodiments, a method comprises: placing a downhole
completion staging system or tool in a wellbore adjacent a
subterranean formation; operating the downhole completion staging
system or tool to establish one or more passages for fluid
communication between the wellbore and the subterranean formation
in a plurality of wellbore stages spaced along the wellbore;
isolating one of the wellbore stages for treatment; injecting a
treatment fluid through the wellbore and the one or more passages
of the isolated wellbore stage into the subterranean formation to
place proppant in a fracture in the subterranean formation;
circulating a stabilized slurry treatment fluid through the
isolated wellbore stage to facilitate removal of proppant from the
wellbore stage; and repeating the isolation, proppant placement and
stabilized slurry treatment fluid circulation for one or more
additional stages.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] 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.
[0012] FIG. 1A shows a schematic of a horizontal well with
perforation clusters according to some embodiments of the current
application.
[0013] FIG. 1B shows a schematic transverse section of the
horizontal well of FIG. 1A as seen along the lines 1B-1B.
[0014] FIG. 1C shows a schematic of a horizontal well with a
plurality of stages of perforation clusters according to
embodiments.
[0015] FIGS. 2A-2C schematically illustrate a wireline completion
staging system or tool according to some embodiments of the present
disclosure.
[0016] FIGS. 3A-3E schematically illustrate a sleeve-based
completion staging system tool according to some embodiments of the
present disclosure.
[0017] FIGS. 4A-4C schematically illustrate activating objects used
in a sleeve-based completion staging system or tool according to
some embodiments of the present disclosure.
[0018] FIGS. 5A-5C schematically illustrate an RFID based
dart-sleeve completion staging system tool according to some
embodiments of the present disclosure.
[0019] FIGS. 6A-6B schematically illustrate a further sleeve-based
completion staging system or tool according to some embodiments of
the present disclosure.
[0020] FIGS. 7A-7E schematically illustrate a jetting completion
staging system or tool according to some embodiments of the present
disclosure.
[0021] FIG. 8 shows a schematic slurry state progression chart for
a treatment fluid according to some embodiments of the current
application.
[0022] FIG. 9 illustrates fluid stability regions for a treatment
fluid according to some embodiments of the current application.
[0023] FIG. 10 shows the leakoff property of a low viscosity,
stabilized treatment slurry (STS) (lower line) according to some
embodiments of the current application compared to conventional
crosslinked fluid (upper line).
DETAILED DESCRIPTION OF SOME ILLUSTRATIVE EMBODIMENTS
[0024] For the purposes of promoting an understanding of the
principles of the disclosure, reference will now be made to some
illustrative embodiments of the current application. Like reference
numerals used herein refer to like parts in the various drawings.
Reference numerals without suffixed letters refer to the part(s) in
general; reference numerals with suffixed letters refer to a
specific one of the parts.
[0025] As used herein, "embodiments" refers to non-limiting
examples of the application disclosed herein, whether claimed or
not, which may be employed or present alone or in any combination
or permutation with one or more other embodiments. Each embodiment
disclosed herein should be regarded both as an added feature to be
used with one or more other embodiments, as well as a further
embodiment to be used separately or in lieu of one or more other
embodiments. It should be understood that no limitation of the
scope of the claimed subject matter is thereby intended, any
alterations and further modifications in the illustrated
embodiments, and any further applications of the principles of the
application as illustrated therein as would normally occur to one
skilled in the art to which the disclosure relates are contemplated
herein.
[0026] Moreover, the schematic illustrations and descriptions
provided herein are understood to be examples only, and components
and operations may be combined or divided, and added or removed, as
well as re-ordered in whole or part, unless stated explicitly to
the contrary herein. Certain operations illustrated may be
implemented by a computer executing a computer program product on a
computer readable medium, where the computer program product
comprises instructions causing the computer to execute one or more
of the operations, or to issue commands to other devices to execute
one or more of the operations.
[0027] It should be understood that, although a substantial portion
of the following detailed description may be provided in the
context of oilfield hydraulic fracturing operations, other oilfield
operations such as cementing, gravel packing, etc., or even
non-oilfield well treatment operations, can utilize and benefit as
well from the disclosure of the present treatment slurry.
[0028] 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.
[0029] 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.
[0030] "Viscosity" as used herein unless otherwise indicated refers
to the apparent dynamic viscosity of a fluid at a temperature of
25.degree. C. and shear rate of 170 s.sup.-1. "Low-shear viscosity"
as used herein unless otherwise indicated refers to the apparent
dynamic viscosity of a fluid at a temperature of 25.degree. C. and
shear rate of 5.11 s.sup.-1. Yield stress and viscosity of the
treatment fluid are evaluated at 25.degree. C. in a Fann 35
rheometer with an R1B5F1 spindle, or an equivalent
rheometer/spindle arrangement, with shear rate ramped up to 255
s.sup.-1 (300 rpm) and back down to 0, an average of the two
readings at 2.55, 5.11, 85.0, 170 and 255 s.sup.-1 (3, 6, 100, 200
and 300 rpm) recorded as the respective shear stress, the apparent
dynamic viscosity is determined as the ratio of shear stress to
shear rate (.tau./.gamma.) at .gamma.=170 s.sup.-1, and the yield
stress (.tau..sub.0) (if any) is determined as the y-intercept
using a best fit of the Herschel-Buckley rheological model,
.tau.=.tau..sub.0+k(.gamma.).sup.n, where .tau. is the shear
stress, k is a constant, .gamma. is the shear rate and n is the
power law exponent. Where the power law exponent is equal to 1, the
Herschel-Buckley fluid is known as a Bingham plastic. Yield stress
as used herein is synonymous with yield point and refers to the
stress required to initiate flow in a Bingham plastic or
Herschel-Buckley fluid system calculated as the y-intercept in the
manner described herein. A "yield stress fluid" refers to a
Herschel-Buckley fluid system, including Bingham plastics or
another fluid system in which an applied non-zero stress as
calculated in the manner described herein is required to initiate
fluid flow.
[0031] The following conventions with respect to slurry terms are
intended herein unless otherwise indicated explicitly or implicitly
by context.
[0032] "Treatment fluid" or "fluid" (in context) refers to the
entire treatment fluid, including any proppant, subproppant
particles, liquid, gas etc. "Whole fluid," "total fluid" and "base
fluid" are used herein to refer to the fluid phase plus any
subproppant particles dispersed therein, but exclusive of proppant
particles. "Carrier," "fluid phase" or "liquid phase" refer to the
fluid or liquid that is present, which may comprise a continuous
phase and optionally one or more discontinuous fluid phases
dispersed in the continuous phase, including any solutes,
thickeners or colloidal particles only, exclusive of other solid
phase particles; reference to "water" in the slurry refers only to
water and excludes any particles, solutes, thickeners, colloidal
particles, etc.; reference to "aqueous phase" refers to a carrier
phase comprised predominantly of water, which may be a continuous
or dispersed phase. As used herein the terms "liquid" or "liquid
phase" encompasses both liquids per se and supercritical fluids,
including any solutes dissolved therein.
[0033] The measurement or determination of the viscosity of the
liquid phase (as opposed to the treatment fluid or base fluid) may
be based on a direct measurement of the solids-free liquid, or a
calculation or correlation based on a measurement(s) of the
characteristics or properties of the liquid containing the solids,
or a measurement of the solids-containing liquid using a technique
where the determination of viscosity is not affected by the
presence of the solids. As used herein, solids-free for the
purposes of determining the viscosity of the liquid phase means in
the absence of non-colloidal particles larger than 1 micron such
that the particles do not affect the viscosity determination, but
in the presence of any submicron or colloidal particles that may be
present to thicken and/or form a gel with the liquid, i.e., in the
presence of ultrafine particles that can function as a thickening
agent. In some embodiments, a "low viscosity liquid phase" means a
viscosity less than about 300 mPa-s measured without any solids
greater than 1 micron at 170 s.sup.-1 and 25.degree. C.
[0034] In some embodiments, the treatment fluid may include a
continuous fluid phase, also referred to as an external phase, and
a discontinuous phase(s), also referred to as an internal phase(s),
which may be a fluid (liquid or gas) in the case of an emulsion,
foam or energized fluid, or which may be a solid in the case of a
slurry. The continuous fluid phase may be any matter that is
substantially continuous under a given condition. Examples of the
continuous fluid phase include, but are not limited to, water,
hydrocarbon, gas, liquefied gas, etc., which may include solutes,
e.g. the fluid phase may be a brine, and/or may include a brine or
other solution(s). In some embodiments, the fluid phase(s) may
optionally include a viscosifying and/or yield point agent and/or a
portion of the total amount of viscosifying and/or yield point
agent present. Some non-limiting examples of the fluid phase(s)
include hydratable gels (e.g. gels containing polysaccharides such
as guars, 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.
[0035] The discontinuous phase if present in the treatment fluid
may be any particles (including fluid droplets) that are suspended
or otherwise dispersed in the continuous phase in a disjointed
manner. In this respect, the discontinuous phase can also be
referred to, collectively, as "particle" or "particulate" which may
be used interchangeably. As used herein, the term "particle" should
be construed broadly. For example, in some embodiments, the
particle(s) of the current application are solid such as proppant,
sands, ceramics, crystals, salts, etc.; however, in some other
embodiments, the particle(s) can be liquid, gas, foam, emulsified
droplets, etc. Moreover, in some embodiments, the particle(s) of
the current application are substantially stable and do not change
shape or form over an extended period of time, temperature, or
pressure; in some other embodiments, the particle(s) of the current
application are degradable, dissolvable, deformable, meltable,
sublimeable, or otherwise capable of being changed in shape, state,
or structure.
[0036] In certain embodiments, the particle(s) is substantially
round and spherical. In some certain embodiments, the particle(s)
is not substantially spherical and/or round, e.g., it can have
varying degrees of sphericity and roundness, according to the API
RP-60 sphericity and roundness index. For example, the particle(s)
may have an aspect ratio, defined as the ratio of the longest
dimension of the particle to the shortest dimension of the
particle, of more than 2, 3, 4, 5 or 6. Examples of such
non-spherical particles include, but are not limited to, fibers,
flakes, discs, rods, stars, etc. All such variations should be
considered within the scope of the current application.
[0037] The particles in the slurry in various embodiments may be
multimodal. As used herein multimodal refers to a plurality of
particle sizes or modes which each has a distinct size or particle
size distribution, e.g., proppant and fines. As used herein, the
terms distinct particle sizes, distinct particle size distribution,
or multi-modes or multimodal, mean that each of the plurality of
particles has a unique volume-averaged particle size distribution
(PSD) mode. That is, statistically, the particle size distributions
of different particles appear as distinct peaks (or "modes") in a
continuous probability distribution function. For example, a
mixture of two particles having normal distribution of particle
sizes with similar variability is considered a bimodal particle
mixture if their respective means differ by more than the sum of
their respective standard deviations, and/or if their respective
means differ by a statistically significant amount. In certain
embodiments, the particles contain a bimodal mixture of two
particles; in certain other embodiments, the particles contain a
trimodal mixture of three particles; in certain additional
embodiments, the particles contain a tetramodal mixture of four
particles; in certain further embodiments, the particles contain a
pentamodal mixture of five particles, and so on. Representative
references disclosing multimodal particle mixtures include U.S.
Pat. No. 5,518,996, U.S. Pat. No. 7,784,541, U.S. Pat. No.
7,789,146, U.S. Pat. No. 8,008,234, U.S. Pat. No. 8,119,574, U.S.
Pat. No. 8,210,249, US 2010/0300688, US 2012/0000641, US
2012/0138296, US 2012/0132421, US 2012/0111563, WO 2012/054456, US
2012/0305245, US 2012/0305254, US 2012/0132421, PCT/RU2011/000971
and U.S. Ser. No. 13/415,025, each of which are hereby incorporated
herein by reference.
[0038] "Solids" and "solids volume" refer to all solids present in
the slurry, including proppant and subproppant particles, including
particulate thickeners such as colloids and submicron particles.
"Solids-free" and similar terms generally exclude proppant and
subproppant particles, except particulate thickeners such as
colloids for the purposes of determining the viscosity of a
"solids-free" fluid. "Proppant" refers to particulates that are
used in well work-overs and treatments, such as hydraulic
fracturing operations, to hold fractures open following the
treatment, of a particle size mode or modes in the slurry having a
weight average mean particle size greater than or equal to about
100 microns, e.g., 140 mesh particles correspond to a size of 105
microns, unless a different proppant size is indicated in the claim
or a smaller proppant size is indicated in a claim depending
therefrom. "Gravel" refers to particles used in gravel packing, and
the term is synonymous with proppant as used herein. "Sub-proppant"
or "subproppant" refers to particles or particle size or mode
(including colloidal and submicron particles) having a smaller size
than the proppant mode(s); references to "proppant" exclude
subproppant particles and vice versa. In some embodiments, the
sub-proppant mode or modes each have a weight average mean particle
size less than or equal to about one-half of the weight average
mean particle size of a smallest one of the proppant modes, e.g., a
suspensive/stabilizing mode.
[0039] The proppant, when present, can be naturally occurring
materials, such as sand grains. The proppant, when present, can
also be man-made or specially engineered, such as coated (including
resin-coated) sand, modulus of various nuts, high-strength ceramic
materials like sintered bauxite, etc. In some embodiments, the
proppant of the current application, when present, has a density
greater than 2.45 g/mL, e.g., 2.5-2.8 g/mL, such as sand, ceramic,
sintered bauxite or resin coated proppant. In some embodiments, the
proppant of the current application, when present, has a density
less than or equal to 2.45 g/mL, such as less than about 1.60 g/mL,
less than about 1.50 g/mL, less than about 1.40 g/mL, less than
about 1.30 g/mL, less than about 1.20 g/mL, less than 1.10 g/mL, or
less than 1.00 g/mL, such as light/ultralight proppant from various
manufacturers, e.g., hollow proppant.
[0040] In some embodiments, the treatment fluid comprises an
apparent specific gravity greater than 1.3, greater than 1.4,
greater than 1.5, greater than 1.6, greater than 1.7, greater than
1.8, greater than 1.9, greater than 2, greater than 2.1, greater
than 2.2, greater than 2.3, greater than 2.4, greater than 2.5,
greater than 2.6, greater than 2.7, greater than 2.8, greater than
2.9, or greater than 3. The treatment fluid density can be selected
by selecting the specific gravity and amount of the dispersed
solids and/or adding a weighting solute to the aqueous phase, such
as, for example, a compatible organic or mineral salt. In some
embodiments, the aqueous or other liquid phase may have a specific
gravity greater than 1, greater than 1.05, greater than 1.1,
greater than 1.2, greater than 1.3, greater than 1.4, greater than
1.5, greater than 1.6, greater than 1.7, greater than 1.8, greater
than 1.9, greater than 2, greater than 2.1, greater than 2.2,
greater than 2.3, greater than 2.4, greater than 2.5, greater than
2.6, greater than 2.7, greater than 2.8, greater than 2.9, or
greater than 3, etc. In some embodiments, the aqueous or other
liquid phase may have a specific gravity less than 1. In
embodiments, the weight of the treatment fluid can provide
additional hydrostatic head pressurization in the wellbore at the
perforations or other fracture location, and can also facilitate
stability by lessening the density differences between the larger
solids and the whole remaining fluid. In other embodiments, a low
density proppant may be used in the treatment, for example,
lightweight proppant (apparent specific gravity less than 2.65)
having a density less than or equal to 2.5 g/mL, such as less than
about 2 g/mL, less than about 1.8 g/mL, less than about 1.6 g/mL,
less than about 1.4 g/mL, less than about 1.2 g/mL, less than 1.1
g/mL, or less than 1 g/mL. In other embodiments, the proppant or
other particles in the slurry may have a specific gravity greater
than 2.6, greater than 2.7, greater than 2.8, greater than 2.9,
greater than 3, etc.
[0041] "Stable" or "stabilized" or similar terms refer to a
stabilized treatment slurry (STS) wherein gravitational settling of
the particles is inhibited such that no or minimal free liquid is
formed, and/or there is no or minimal rheological variation among
strata at different depths in the STS, and/or the slurry may
generally be regarded as stable over the duration of expected STS
storage and use conditions, e.g., an STS that passes a stability
test or an equivalent thereof. In certain embodiments, stability
can be evaluated following different settling conditions, such as
for example static under gravity alone, or dynamic under a
vibratory influence, or dynamic-static conditions employing at
least one dynamic settling condition followed and/or preceded by at
least one static settling condition.
[0042] 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.
[0043] In certain embodiments, one stability test is referred to
herein as the "8 h@15 Hz/10 d-static STS stability test", wherein a
slurry sample is evaluated in a rheometer at the beginning of the
test and compared against different strata of a slurry sample
placed and sealed in a 152 mm (6 in.) diameter vertical
gravitational settling column filled to a depth of 2.13 m (7 ft),
vibrated at 15 Hz with a 1 mm amplitude (vertical displacement) two
4-hour periods the first and second settling days, and thereafter
maintained in a static condition for 10 days (12 days total
settling time). The 15 Hz/1 mm amplitude condition in this test is
selected to correspond to surface transportation and/or storage
conditions prior to the well treatment. At the end of the settling
period the depth of any free water at the top of the column is
measured, and samples obtained, in order from the top sampling port
down to the bottom, through 25.4-mm sampling ports located on the
settling column at 190 mm (6'3''), 140 mm (4'7''), 84 mm (2'9'')
and 33 mm (1'1''), and rheologically evaluated for viscosity and
yield stress as described above.
[0044] As used herein, a stabilized treatment slurry (STS) may meet
at least one of the following conditions: [0045] (1) the slurry has
a low-shear viscosity equal to or greater than 1 Pa-s (5.11
s.sup.-1, 25.degree. C.); [0046] (2) the slurry has a
Herschel-Buckley (including Bingham plastic) yield stress (as
determined in the manner described herein) equal to or greater than
1 Pa; or [0047] (3) the largest particle mode in the slurry has a
static settling rate less than 0.01 mm/hr; or [0048] (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 [0049] (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 [0050] (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
[0051] (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.
[0052] In embodiments, the depth of any free fluid at the end of
the 8 h@15 Hz/10 d-static dynamic settling test condition is no
more than 2% of total depth, the apparent dynamic viscosity
(25.degree. C., 170 s-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.
[0053] In some embodiments, 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) 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.
[0054] In some embodiments, the stabilized slurry comprises at
least two of the stability indicia, such as for example, the SVF of
at least 0.4 and the low-shear viscosity of at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.); and optionally one or more of the yield
stress of at least 1 Pa, the apparent viscosity of at least 50
mPa-s (170 s.sup.-1, 25.degree. C.), the multimodal solids phase,
the solids phase having a PVF greater than 0.7, the viscosifier,
the colloidal particles, the particle-fluid density delta less than
1.6 g/mL, the particles having an aspect ratio of at least 6, the
ciliated or coated proppant, or a combination thereof.
[0055] In some embodiments, the stabilized slurry comprises at
least three of the stability indicia, such as for example, the SVF
of at least 0.4, the low-shear viscosity of at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.) and the yield stress of at least 1 Pa; and
optionally one or more of the apparent viscosity of at least 50
mPa-s (170 s.sup.-1, 25.degree. C.), the multimodal solids phase,
the solids phase having a PVF greater than 0.7, the viscosifier,
the colloidal particles, the particle-fluid density delta less than
1.6 g/mL, the particles having an aspect ratio of at least 6, the
ciliated or coated proppant, or a combination thereof.
[0056] In some embodiments, the stabilized slurry comprises at
least four of the stability indicia, such as for example, the SVF
of at least 0.4, the low-shear viscosity of at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.), the yield stress of at least 1 Pa and the
apparent viscosity of at least 50 mPa-s (170 s.sup.-1, 25.degree.
C.); and optionally one or more of the multimodal solids phase, the
solids phase having a PVF greater than 0.7, the viscosifier,
colloidal particles, the particle-fluid density delta less than 1.6
g/mL, the particles having an aspect ratio of at least 6, the
ciliated or coated proppant, or a combination thereof.
[0057] In some embodiments, the stabilized slurry comprises at
least five of the stability indicia, such as for example, the SVF
of at least 0.4, the low-shear viscosity of at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.), the yield stress of at least 1 Pa, the
apparent viscosity of at least 50 mPa-s (170 s.sup.-1, 25.degree.
C.) and the multimodal solids phase, and optionally one or more of
the solids phase having a PVF greater than 0.7, the viscosifier,
colloidal particles, the particle-fluid density delta less than 1.6
g/mL, the particles having an aspect ratio of at least 6, the
ciliated or coated proppant, or a combination thereof.
[0058] In some embodiments, the stabilized slurry comprises at
least six of the stability indicia, such as for example, the SVF of
at least 0.4, the low-shear viscosity of at least 1 Pa-s (5.11
s.sup.-1, 25.degree. C.), the yield stress of at least 1 Pa, the
apparent viscosity of at least 50 mPa-s (170 s.sup.-1, 25.degree.
C.), the multimodal solids phase and one or more of the solids
phase having a PVF greater than 0.7, and optionally the
viscosifier, colloidal particles, the particle-fluid density delta
less than 1.6 g/mL, the particles having an aspect ratio of at
least 6, the ciliated or coated proppant, or a combination
thereof.
[0059] In embodiments, the treatment slurry is formed (stabilized)
by at least one of the following slurry stabilization operations:
(1) introducing sufficient particles into the slurry or treatment
fluid to increase the SVF of the treatment fluid to at least 0.4;
(2) increasing a low-shear viscosity of the slurry or treatment
fluid to at least 1 Pa-s (5.11 s.sup.-1, 25.degree. C.); (3)
increasing a yield stress of the slurry or treatment fluid to at
least 1 Pa; (4) increasing apparent viscosity of the slurry or
treatment fluid to at least 50 mPa-s (170 s.sup.-1, 25.degree. C.);
(5) introducing a multimodal solids phase into the slurry or
treatment fluid; (6) introducing a solids phase having a PVF
greater than 0.7 into the slurry or treatment fluid; (7)
introducing into the slurry or treatment fluid a viscosifier
selected from viscoelastic surfactants, e.g., in an amount ranging
from 0.01 up to 7.2 g/L (60 ppt), and hydratable gelling agents,
e.g., in an amount ranging from 0.01 up to 4.8 g/L (40 ppt) based
on the volume of fluid phase; (8) introducing colloidal particles
into the slurry or treatment fluid; (9) reducing a particle-fluid
density delta to less than 1.6 g/mL (e.g., introducing particles
having a specific gravity less than 2.65 g/mL, carrier fluid having
a density greater than 1.05 g/mL or a combination thereof); (10)
introducing particles into the slurry or treatment fluid having an
aspect ratio of at least 6; (11) introducing ciliated or coated
proppant into slurry or treatment fluid; and (12) combinations
thereof. The 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.
[0060] The techniques to stabilize particle settling in various
embodiments herein may use any one, or a combination of any two or
three, or all of these approaches, i.e., a manipulation of
particle/fluid density, carrier fluid viscosity, solids fraction,
yield stress, and/or may use another approach. In embodiments, the
stabilized slurry is formed by at least two of the slurry
stabilization operations, such as, for example, increasing the SVF
and increasing the low-shear viscosity of the treatment fluid, and
optionally one or more of increasing the yield stress, increasing
the apparent viscosity, introducing the multimodal solids phase,
introducing the solids phase having the PVF greater than 0.7,
introducing the viscosifier, introducing the colloidal particles,
reducing the particle-fluid density delta, introducing the
particles having the aspect ratio of at least 6, introducing the
ciliated or coated proppant or a combination thereof.
[0061] In embodiments, the stabilized slurry is formed by at least
three of the slurry stabilization operations, such as, for example,
increasing the SVF, increasing the low-shear viscosity and
introducing the multimodal solids phase, and optionally one or more
of increasing the yield stress, increasing the apparent viscosity,
introducing the solids phase having the PVF greater than 0.7,
introducing the viscosifier, introducing the colloidal particles,
reducing the particle-fluid density delta, introducing the
particles having the aspect ratio of at least 6, introducing the
ciliated or coated proppant or a combination thereof.
[0062] In embodiments, the stabilized slurry is formed by at least
four of the slurry stabilization operations, such as, for example,
increasing the SVF, increasing the low-shear viscosity, increasing
the yield stress and increasing apparent viscosity, and optionally
one or more of introducing the multimodal solids phase, introducing
the solids phase having the PVF greater than 0.7, introducing the
viscosifier, introducing colloidal particles, reducing the
particle-fluid density delta, introducing particles into the
treatment fluid having the aspect ratio of at least 6, introducing
the ciliated or coated proppant or a combination thereof.
[0063] In embodiments, the stabilized slurry is formed by at least
five of the slurry stabilization operations, such as, for example,
increasing the SVF, increasing the low-shear viscosity, increasing
the yield stress, increasing the apparent viscosity and introducing
the multimodal solids phase, and optionally one or more of
introducing the solids phase having the PVF greater than 0.7,
introducing the viscosifier, introducing colloidal particles,
reducing the particle-fluid density delta, introducing particles
into the treatment fluid having the aspect ratio of at least 6,
introducing the ciliated or coated proppant or a combination
thereof.
[0064] Decreasing the density difference between the particle and
the carrier fluid may be done in embodiments by employing porous
particles, including particles with an internal porosity, i.e.,
hollow particles. However, the porosity may also have a direct
influence on the mechanical properties of the particle, e.g., the
elastic modulus, which may also decrease significantly with an
increase in porosity. In certain embodiments employing particle
porosity, care should be taken so that the crush strength of the
particles exceeds the maximum expected stress for the particle,
e.g., in the embodiments of proppants placed in a fracture the
overburden stress of the subterranean formation in which it is to
be used should not exceed the crush strength of the proppants.
[0065] In embodiments, yield stress fluids, and also fluids having
a high low-shear viscosity, are used to retard the motion of the
carrier fluid and thus retard particle settling. The gravitational
stress exerted by the particle at rest 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.
[0066] Increasing carrier fluid viscosity in a Newtonian fluid also
proportionally increases the resistance of the carrier fluid
motion. In some embodiments, the fluid carrier has a lower limit of
apparent dynamic viscosity, determined at 170 s.sup.-1 and
25.degree. C., of at least about 0.1 mPa-s, or at least about 1
mPa-s, or at least about 10 mPa-s, or at least about 25 mPa-s, or
at least about 50 mPa-s, or at least about 75 mPa-s, or at least
about 100 mPa-s, or at least about 150 mPa-s. A disadvantage of
increasing the viscosity is that as the viscosity increases, the
friction pressure for pumping the slurry generally increases as
well. In some embodiments, the fluid carrier has an upper limit of
apparent dynamic viscosity, determined at 170 s.sup.-1 and
25.degree. C., of less than about 300 mPa-s, or less than about 150
mPa-s, or less than about 100 mPa-s, or less than about 75 mPa-s,
or less than about 50 mPa-s, or less than about 25 mPa-s, or less
than about 10 mPa-s. In embodiments, the fluid phase viscosity
ranges from any lower limit to any higher upper limit.
[0067] In some embodiments, an agent may both viscosify and impart
yield stress characteristics, and in further embodiments may also
function as a friction reducer to reduce friction pressure losses
in pumping the treatment fluid. In embodiments, the liquid phase is
essentially free of viscosifier or comprises a viscosifier in an
amount ranging from 0.01 up to 2.4 g/L (0.08-20 lb/1000 gals) of
the fluid phase. The viscosifier can be a viscoelastic surfactant
(VES) or a hydratable gelling agent such as a polysaccharide, which
may be crosslinked. When using viscosifiers and/or yield stress
fluids, it may be useful to consider the need for and if necessary
implement a clean-up procedure, i.e., removal or inactivation of
the viscosifier and/or yield stress fluid during or following the
treatment procedure, since fluids with viscosifiers and/or yield
stresses may present clean up difficulties in some situations or if
not used correctly. In certain embodiments, clean up can be
effected using a breaker(s). In some embodiments, the slurry is
stabilized for storage and/or pumping or other use at the surface
conditions, and clean-up is achieved downhole at a later time and
at a higher temperature, e.g., for some formations, the temperature
difference between surface and downhole can be significant and
useful for triggering degradation of the viscosifier, the
particles, a yield stress agent or characteristic, and/or a
breaker. Thus in some embodiments, breakers that are either
temperature sensitive or time sensitive, either through delayed
action breakers or delay in mixing the breaker into the slurry, can
be useful.
[0068] In certain embodiments, the fluid may be stabilized by
introducing colloidal particles into the treatment fluid, such as,
for example, colloidal silica, which may function as a gellant
and/or thickener.
[0069] In addition or as an alternative to increasing the viscosity
of the carrier fluid (with or without density manipulation),
increasing the volume fraction of the particles in the treatment
fluid can also hinder movement of the carrier fluid. Where the
particles are not deformable, the particles interfere with the flow
of the fluid around the settling particle to cause hindered
settling. The addition of a large volume fraction of particles can
be complicated, however, by increasing fluid viscosity and pumping
pressure, and increasing the risk of loss of fluidity of the slurry
in the event of carrier fluid losses. In some embodiments, the
treatment fluid has a lower limit of apparent dynamic viscosity,
determined at 170 s.sup.-1 and 25.degree. C., of at least about 1
mPa-s, or at least about 10 mPa-s, or at least about 25 mPa-s, or
at least about 50 mPa-s, or at least about 75 mPa-s, or at least
about 100 mPa-s, or at least about 150 mPa-s, or at least about 300
mPa-s, and an upper limit of apparent dynamic viscosity, determined
at 170 s.sup.-1 and 25.degree. C., of less than about 500 mPa-s, or
less than about 300 mPa-s, or less than about 150 mPa-s, or less
than about 100 mPa-s, or less than about 75 mPa-s, or less than
about 50 mPa-s, or less than about 25 mPa-s, or less than about 10
mPa-s. In embodiments, the treatment fluid viscosity ranges from
any lower limit to any higher upper limit.
[0070] In embodiments, the treatment fluid may be stabilized by
introducing sufficient particles into the treatment fluid to
increase the SVF of the treatment fluid, e.g., to at least 0.5. In
a powder or particulated medium, the packed volume fraction (PVF)
is defined as the volume of space occupied by the particles (the
absolute volume) divided by the bulk volume, i.e., the total volume
of the particles plus the void space between them:
PVF=Particle volume/(Particle volume+Non-particle
Volume)=1-.phi.
For the purposes of calculating PVF and slurry solids volume
fraction (SVF) herein, the particle volume includes the volume of
any colloidal and/or submicron particles.
[0071] Here, the porosity, .phi., is the void fraction of the
powder pack. Unless otherwise specified the PVF of a particulated
medium is determined in the absence of overburden or other
compressive force that would deform the packed solids. The packing
of particles (in the absence of overburden) is a purely geometrical
phenomenon. Therefore, the PVF depends only on the size and the
shape of particles. The most ordered arrangement of monodisperse
spheres (spheres with exactly the same size in a compact hexagonal
packing) has a PVF of 0.74. However, such highly ordered
arrangements of particles rarely occur in industrial operations.
Rather, a somewhat random packing of particles is prevalent in
oilfield treatment. Unless otherwise specified, particle packing in
the current application means random packing of the particles. A
random packing of the same spheres has a PVF of 0.64. In other
words, the randomly packed particles occupy 64% of the bulk volume,
and the void space occupies 36% of the bulk volume. A higher PVF
can be achieved by preparing blends of particles that have more
than one particle size and/or a range(s) of particle sizes. The
smaller particles can fit in the void spaces between the larger
ones.
[0072] The PVF in embodiments can therefore be increased by using a
multimodal particle mixture, for example, coarse, medium and fine
particles in specific volume ratios, where the fine particles can
fit in the void spaces between the medium-size particles, and the
medium size particles can fit in the void space between the coarse
particles. For some embodiments of two consecutive size classes or
modes, the ratio between the mean particle diameters (d.sub.50) of
each mode may be between 7 and 10. In such cases, the PVF can
increase up to 0.95 in some embodiments. By blending coarse
particles (such as proppant) with other particles selected to
increase the PVF, only a minimum amount of fluid phase (such as
water) is needed to render the treatment fluid pumpable. Such
concentrated suspensions (i.e. slurry) tend to behave as a porous
solid and may shrink under the force of gravity. This is a hindered
settling phenomenon as discussed above and, as mentioned, the
extent of solids-like behavior generally increases with the slurry
solid volume fraction (SVF), which is given as
SVF=Particle volume/(Particle volume+Liquid volume)
[0073] It follows that proppant or other large particle mode
settling in multimodal embodiments can if desired be minimized
independently of the viscosity of the continuous phase. Therefore,
in some embodiments little or no viscosifier and/or yield stress
agent, e.g., a gelling agent, is required to inhibit settling and
achieve particle transport, such as, for example, less than 2.4
g/L, less than 1.2 g/L, less than 0.6 g/L, less than 0.3 g/L, less
than 0.15 g/L, less than 0.08 g/L, less than 0.04 g/L, less than
0.2 g/L or less than 0.1 g/L of viscosifier may be present in the
STS.
[0074] It is helpful for an understanding of the current
application to consider the amounts of particles present in the
slurries of various embodiments of the treatment fluid. The minimum
amount of fluid phase necessary to make a homogeneous slurry blend
is the amount required to just fill all the void space in the PVF
with the continuous phase, i.e., when SVF=PVF. However, this blend
may not be flowable since all the solids and liquid may be locked
in place with no room for slipping and mobility. In flowable system
embodiments, SVF may be lower than PVF, e.g., SVF/PVF 0.99. In this
condition, in a stabilized treatment slurry, essentially all the
voids are filled with excess liquid to increase the spacing between
particles so that the particles can roll or flow past each other.
In some embodiments, the higher the PVF, the lower the SVF/PVF
ratio should be to obtain a flowable slurry.
[0075] With reference to the embodiments of FIGS. 1A-1B, a cased
and cemented horizontal well 10 is configured to receive a
treatment stage for simultaneously introducing treatment fluid
through a plurality of perforations 12, creating at least one
fracture or a plurality of fractures, or multiple fractures 14A,
14B, 14C, 14D. The treatment stage in these embodiments is provided
with four corresponding cluster sets 16A, 16B, 16C, 16D to form the
respective fractures 14A, 14B, 14C, 14D. Four cluster sets are
shown for purposes of illustration and example, but the invention
is not limited to any particular number of cluster sets in the
stage. Each cluster set 16A, 16B, 16C, 16D is provided with a
plurality of radially arrayed perforations 12 (see FIG. 1B). A
fracture plug 108, which may be mechanical, chemical or
particulate-based (e.g., sand), may be provided to isolate the
stage for treatment. The treatment stage may have the number and/or
size of the perforations in the individual clusters and/or the
number of clusters determined for the appropriate amount and rate
of proppant to be delivered. The amount of proppant delivered to
each fracture is generally determined by the relative number of
perforations in the particular cluster associated with the
respective fracture in question.
[0076] With reference to the plural stage embodiments of FIG. 1C,
three stages 20A, 20B, 20C are shown for purposes of illustrating
and exemplifying multistage embodiments of the FIG. 1C arrangement,
but the invention is not limited to any particular number of
stages. Each stage 20A, 20B, 20C in these embodiments is provided
with four cluster sets 16 to form the respective fractures 14, as
in FIG. 1C. The fracture plugs 18A, 18B, 18C are provided to
isolate each respective stage 20A, 20B, 20C for treatment. As in
FIG. 1C, the fracture plugs may be mechanical, chemical or
particulate-based, each stage may have the number and/or size of
the perforations in the individual clusters and/or the number of
clusters determined for the appropriate amount and rate of proppant
to be delivered for the particular stage; and the amount of
proppant delivered to each fracture is also generally determined by
the relative number of perforations in the particular cluster
associated with the fracture in question. In particular
embodiments, the fracture plugs may be formed by bridging the
solids in the treatment slurry, and/or optionally debridged by
re-slurrying the solids in the treatment fluid.
[0077] With reference to FIGS. 2A-2C, in embodiments the downhole
completion staging system or tool 40 comprises a wireline tool
string 42 made up of a blanking plug 44 and perforating guns 46. In
the so-called "plug and perf" completion system, the wireline tool
string 42 is run-in-hole in embodiments as shown in FIG. 2A. The
tool string 42 includes the blanking plug 44 and perforating guns
46. The blanking plug 44 is positioned and set in the wellbore, and
one or more perforation clusters 48 are then placed in the wellbore
above the wireline plug, as shown in FIG. 2B in embodiments. The
wireline equipment is recovered to surface. A fracture treatment is
then circulated down the wellbore to the formation to form
fracture(s) 50 adjacent the perforations 48, as shown in FIG. 2C.
In embodiments the fracture treatment is circulated into the
wellbore with the stabilized slurry treatment fluid.
[0078] In other embodiments, the so-called just-in-time perforating
(JITP) technique is employed using the stabilized slurry treatment
fluid. As used herein, JITP refers to a multizone perforation
method wherein the perforating device is moved within the wellbore
between stages without removing it from the wellbore between stages
so that perforation of serial stages can proceed continuously and
sequentially. The JITP technique is known from, for example, U.S.
Pat. No. 6,394,184, U.S. Pat. No. 6,520,255, U.S. Pat. No.
6,543,538, U.S. Pat. No. 6,575,247, US 2009/0114392, SPE-152100,
and King, Optimize multizone fracturing, E&P Magazine (Aug. 29,
2007), which are hereby incorporated herein by reference. Briefly,
in embodiments, the method comprises perforating an interval in a
wellbore with a perforating device, injecting a treatment fluid
into the perforations created without removing the perforating
device from the wellbore, moving the perforating device away from
the perforations created before or after the treatment fluid
injection, deploying a diversion agent to block further flow into
the perforations created, and repeating the perforation and
injection for one or more additional intervals, wherein a
stabilized slurry treatment fluid is used in the injection, or as a
flush fluid circulated in the wellbore after the injection, or a
combination thereof. In embodiments, the diversion agent(s) may be
selected from one or more of mechanical devices such as bridge
plugs, packers, down-hole valves, sliding sleeves, and baffle/plug
combinations; ball sealers; particulates such as sand, ceramic
material, proppant, salt, waxes, resins, or other compounds; or by
alternative fluid systems such as viscosified fluids, gelled
fluids, or foams, or other chemically formulated fluids.
[0079] In embodiments, the JITP method may coordinate pumping and
perforating, e.g., a wireline or coiled tubing assembly of
perforating guns for a plurality (e.g., 6-11) perforation sets is
run into the wellbore, a set of perforations is made, then the
perforating guns are pulled above the next zone to be perforated,
and the treatment fluid is injected into the just-perforated zone,
while the perforating guns are slowly lowered to the next zone to
be perforated. In embodiments, at the end of the treatment fluid
injection, a diversion agent such as ball sealers, for example, is
delivered to the perforations just treated in the flush fluid
circulated between stages, and if desired, the flush fluid behind
the ball sealers may be used as the pad and/or treatment fluid for
treatment of the next perforated interval. In some embodiments,
sealing of the open perforations with the ball sealers or other
diversion agent is confirmed by a rapid increase in the wellhead
pressure, indicating that the next zone can be immediately
perforated, e.g., while maintaining an overbalanced condition to
maintain the diversion agent to block flow to the existing
perforations and/or the previously treated intervals. In
embodiments, the stabilized slurry treatment fluid described herein
is employed in the injection step, as the pad or flush fluid, or as
any combination thereof.
[0080] With reference to FIGS. 3A-6B, in embodiments the downhole
completion staging system or tool comprises a sleeve-based system.
Generally, sliding sleeves in the closed position are fitted to the
production liner. The production liner is placed in a hydrocarbon
formation. An object is introduced into the wellbore from surface,
and the object is transported to the target zone by the flow field.
When at the target location, the object is caught by the sliding
sleeve and shifts the sleeve to the open position. The object
remains in the sleeve, obstructing hydraulic communication from
above to below. A fracture treatment is then circulated down the
wellbore to the formation adjacent the open sleeve. In embodiments
the fracture treatment is circulated into the wellbore with the
stabilized slurry treatment fluid. Representative examples of
sleeve-based systems are disclosed in U.S. Pat. No. 7,387,165, U.S.
Pat. No. 7,322,417, U.S. Pat. No. 7,377,321, US 2007/0107908, US
2007/0044958, US 2010/0209288, U.S. Pat. No. 7,387,165,
US2009/0084553, U.S. Pat. No. 7,108,067, U.S. Pat. No. 7,431,091,
U.S. Pat. No. 7,543,634, U.S. Pat. No. 7,134,505, U.S. Pat. No.
7,021,384, U.S. Pat. No. 7,353,878, U.S. Pat. No. 7,267,172, U.S.
Pat. No. 7,681,645, U.S. Pat. No. 7,066,265, U.S. Pat. No.
7,168,494, U.S. Pat. No. 7,353,879, U.S. Pat. No. 7,093,664, and
U.S. Pat. No. 7,210,533, which are hereby incorporated herein by
reference.
[0081] FIGS. 3A-3E illustrate embodiments employing a TEST AND
PRODUCE (TAP) cased hole system disclosed in U.S. Pat. No.
7,387,165, U.S. Pat. No. 7,322,417, U.S. Pat. No. 7,377,321.
Briefly the system includes a series of valves 60 for isolating
multiple production zones. Each valve 60 includes a valve sleeve 62
moveable between a closed position blocking radial openings in an
outer housing 64 and an open position where the radial openings are
exposed. The valve 60 also includes a piston 66 and a collapsible
seat 68 which is movable between a pass through state, allowing a
ball or dart to pass through it, and a ball or dart catching
state.
[0082] To isolate a zone, first the seat 68 is collapsed by
increasing pressure through control line 70 to move piston 66
downwardly as shown viewing FIGS. 3B and 3C together. This downward
movement causes mating slanted surfaces 72 of the piston 66 and
C-ring 68 to interact to close the C-ring. The C-ring is now in
position to catch a ball or dart as shown in FIG. 3D. Dart 74 can
now be dropped and caught by C-ring 68. The dart 74 and C-ring 68
now form a fluid tight barrier. Pumping fluid against the dart 74
shears a pin 76 allowing the valve sleeve 62 to move downwardly and
out of blocking engagement with the radial openings. A treatment
fluid can then be injected through the fracture port openings and
into the formation.
[0083] In different embodiments shown in FIG. 3E, the sleeve 78
includes a first set of ports 80 and a another set of ports
adjacent to a filter 82. This assembly works exactly like the one
in FIGS. 3A-3D except with pressure down on the dart there are two
positions: an open valve "treating" position where ports 80 and 84
are aligned, and an open port producing position where the filter
82 is adjacent to ports 84 to inhibit proppant or sand from leaving
the formation.
[0084] FIGS. 4A-4C illustrate embodiments for dissolvable materials
as disclosed in US 2007/0107908, US 2007/0044958, US 2010/0209288.
Briefly, a ball 86, 88 or a dart 90 is made up of inner material 92
which is a combination of an insoluble metal and a soluble additive
so that the combination forms a high strength material that is
dissolvable in an aqueous solution. This inner material 92 is then
coated with an insoluble protective layer 94 to delay the
dissolution. The ball 88, 90 or dart 92 may include openings 96
drilled into the ball to allow dissolving of the ball or dart to
begin immediately upon dropping the ball into the well. The rate of
dissolution of the ball 10, 20 or dart 30 can be controlled by
altering the type and amount of the additive or altering the number
or size of the openings 16.
[0085] FIGS. 5A-5C illustrate a smart dart system disclosed in U.S.
Pat. No. 7,387,165, US2009/0084553. Briefly, in these embodiments a
casing 100 is cemented in place and a number of valves 102A-C are
provided integral with the casing. Each valve 102A-C has a movable
sleeve 104 (see FIG. 5C) and seat of the same size. However, the
seat is not collapsible. Instead, the dart 106 is deployed with its
fins 108 collapsed. To actuate the fins, each valve 102A-C has a
transmitter 110A-C which emits a unique RF signal, and each dart in
turn includes a receiver 112 for receiving a particular target RF
signal. As the dart 106 comes into proximity with a valve emitting
its target RF signal, the fins 108 spring radially outwardly into a
position to engage a seat and form a seal. Continuing to pump down
on the dart then enables the sleeve 114 to be lowered to expose a
fracture port and allow the fracture treatment fluid to enter the
formation.
[0086] The multistage system shown in FIGS. 6A-6B is an open hole
system. With reference to FIG. 6A, the assembly includes a tubing
120 with preformed ports 122 that are covered by shearable end caps
124. The tubing 120 is run in hole with all of the ports covered
and then packers 126A-C are set to isolate various zones of
interest in the formation. When ready to stimulate, a ball 128C is
dropped from surface to seat into seat D1 in sliding sleeve 130C,
thus creating a barrier in the sliding sleeve. Fluid can then be
pumped down on the ball 128C to push the sliding sleeve 130C
downwardly to shear the end caps 124 in the area of ported interval
132C. With these end caps sheared, ports 122 in the area of ported
interval 132C are opened, and the ball/sleeve interface creates a
barrier below the ported interval 132C. Thus, a treatment fluid can
be directed through the ports 122 in ported interval 132C and
packers 126B and 126C will isolate the flow to the adjacent
formation in the area of ported interval 132C. To stimulate the
next zones, successively larger balls are dropped into respective
successively larger seats D2, D3 near the successively higher
formation zones causing end caps in intervals 132B, 132A to shear,
blocking flow below the respective interval, allowing a treatment
fluid to be directed through the ports 122 in the respective ported
interval.
[0087] FIG. 6B operates in a similar manner except instead of using
end caps, each port 140 is initially covered by a port blocking
sleeve 142. Each port blocking sleeve 142 includes a recess 144
such that when the sliding sleeve 146 engages it, dogs 148 on the
sliding sleeve 146 spring outwardly into the respective recess 144
allowing the sliding sleeve 146 to lock with the port blocking
sleeve 142 and pull it downwardly to uncover the ports. As shown,
there can be a series of port blocking sleeves 142 within the same
zone each of which can be moved by the sliding sleeve 146. The
remainder of this embodiment is identical to the previously
described embodiment. That is, the ball/sleeve interface creates a
barrier below the ports to direct a treatment fluid into a
formation of interest. Packers isolate the formation above and
below the ports, and after a treatment has been performed a larger
ball can be dropped into a large seat near a next higher formation
zone.
[0088] With reference to FIGS. 7A-7E, in embodiments the downhole
completion staging system or tool 200 comprises a jetting assembly
fitted to the lower end of the pipe. The jetting assembly 202 is
positioned adjacent the zone of interest, and the casing 204 is
perforated by circulating abrasive materials down the tubing 206
through the jetting assembly into jets 208 as shown in the
embodiments of FIGS. 7A-7B. The annulus 210 is closed in to enable
breaking down the perforations 212. The fracture treatment is then
pumped down the annulus. The tool string can be moved up the way,
and act as a dead string for fracture diagnostics. A final proppant
stafe of non-crosslinked fluid with high proppant concentration is
then pumped to induce a near-wellbore proppant pack that can act as
a diversion for subsequent treatments up the way. In embodiments
the fracture treatment is circulated into the wellbore with the
stabilized slurry treatment fluid.
[0089] In embodiments, the downhole completion staging system or
tool comprises a bottom hole assembly (BHA) equipped with
perforating guns, mechanical set packer and circulating valve. When
at depth, the casing is shot with a perforating gun. The string is
then lowered and the packer is set below the perforations, and the
circulation valve is closed. A fracture treatment is then
circulated down the annular side of the wellbore to the formation
adjacent the perforations. In embodiments the fracture treatment is
circulated into the wellbore with the low stabilized slurry
treatment fluid. After the frac is placed, the circulation is
opened and the wellbore may be cleaned up. In embodiments, the
stabilized slurry treatment fluid is circulated in the wellbore for
cleanup. The process is then repeated for the next zone up the
way.
[0090] FIG. 8 shows a slurry state progression chart for a system
600 having a particle mix with added fluid phase. The first fluid
602 does not have enough liquid added to fill the pore spaces of
the particles, or in other words the SVF/PVF is greater than 1.0.
The first fluid 602 is not flowable. The second fluid 604 has just
enough fluid phase to fill the pore spaces of the particles, or in
other words the SVF/PVF is equal to 1.0. Testing determines whether
the second fluid 604 is flowable and/or pumpable, but a fluid with
an SVF/PVF of 1.0 is generally not flowable or barely flowable due
to an excessive apparent viscosity and/or yield stress. The third
fluid 606 has slightly more fluid phase than is required to fill
the pore spaces of the particles, or in other words the SVF/PVF is
just less than 1.0. A range of SVF/PVF values less than 1.0 will
generally be flowable and/or pumpable or mixable, and if it does
not contain too much fluid phase (and/or contains an added
viscosifier) the third fluid 606 is stable. The values of the range
of SVF/PVF values that are pumpable, flowable, mixable, and/or
stable are dependent upon, without limitation, the specific
particle mixture, fluid phase viscosity, the PVF of the particles,
and the density of the particles. Simple laboratory testing of the
sort ordinarily performed for fluids before fracturing treatments
can readily determine the stability (e.g., the STS stability test
as described herein) and flowability (e.g., apparent dynamic
viscosity at 170 s.sup.-1 and 25.degree. C. of less than about
10,000 mPa-s).
[0091] The fourth fluid 608 shown in FIG. 8 has more fluid phase
than the third fluid 606, to the point where the fourth fluid 608
is flowable but is not stabilized and settles, forming a layer of
free fluid phase at the top (or bottom, depending upon the
densities of the particles in the fourth fluid 608). The amount of
free fluid phase and the settling time over which the free fluid
phase develops before the fluid is considered unstable are
parameters that depend upon the specific circumstances of a
treatment, as noted above. For example, if the settling time over
which the free liquid develops is greater than a planned treatment
time, then in one example the fluid would be considered stable.
Other factors, without limitation, that may affect whether a
particular fluid remains stable include the amount of time for
settling and flow regimes (e.g. laminar, turbulent, Reynolds number
ranges, etc.) of the fluid flowing in a flow passage of interest or
in an agitated vessel, e.g., the amount of time and flow regimes of
the fluid flowing in the wellbore, fracture, etc., and/or the
amount of fluid leakoff occurring in the wellbore, fracture, etc. A
fluid that is stable for one fracturing treatment may be unstable
for a second fracturing treatment. The determination that a fluid
is stable at particular conditions may be an iterative
determination based upon initial estimates and subsequent modeling
results. In some embodiments, the stabilized treatment fluid passes
the STS test described herein.
[0092] FIG. 9 shows a data set 700 of various essentially Newtonian
fluids without any added viscosifiers and without any yield stress,
which were tested for the progression of slurry state on a plot of
SVF/PVF as a function of PVF. The fluid phase in the experiments
was water and the solids had specific gravity 2.6 g/mL. Data points
702 indicated with a triangle were values that had free water in
the slurry, data points 704 indicated with a circle were slurriable
fluids that were mixable without excessive free water, and data
points 706 indicated with a diamond were not easily mixable
liquid-solid mixtures. The data set 700 includes fluids prepared
having a number of discrete PVF values, with liquid added until the
mixture transitions from not mixable to a slurriable fluid, and
then further progresses to a fluid having excess settling. At an
example for a solids mixture with a PVF value near PVF=0.83, it was
observed that around an SVF/PVF value of 0.95 the fluid transitions
from an unmixable mixture to a slurriable fluid. At around an
SVF/PVF of 0.7, the fluid transitions from a stable slurry to an
unstable fluid having excessive settling. It can be seen from the
data set 700 that the compositions can be defined approximately
into a non-mixable region 710, a slurriable region 712, and a
settling region 714.
[0093] FIG. 9 shows the useful range of SVF and PVF for slurries in
embodiments without gelling agents. In some embodiments, the SVF is
less than the PVF, or the ratio SVF/PVF is within the range from
about 0.6 or about 0.65 to about 0.95 or about 0.98. Where the
liquid phase has a viscosity less than 10 mPa-s or where the
treatment fluid is water essentially free of thickeners, in some
embodiments PVF is greater than 0.72 and a ratio of SVF/PVF is
greater than about 1-2.1*(PVF-0.72) for stability (non-settling).
Where the PVF is greater than 0.81, in some embodiments a ratio of
SVF/PVF may be less than 1-2.1*(PVF-0.81) for mixability
(flowability). Adding thickening or suspending agents, or solids
that perform this function such as calcium carbonate or colloids,
i.e., to increase viscosity and/or impart a yield stress, in some
embodiments allows fluids otherwise in the settling area 714
embodiments (where SVF/PVF is less than or equal to about
1-2.1*(PVF-0.72)) to also be useful as an STS or in applications
where a non-settling, slurriable/mixable slurry is beneficial,
e.g., where the treatment fluid has a viscosity greater than 10
mPa-s, greater than 25 mPa-s, greater than 50 mPa-s, greater than
75 mPa-s, greater than 100 mPa-s, greater than 150 mPa-s, or
greater than 300 mPa-s; and/or a yield stress greater than 0.1 Pa,
greater than 0.5 Pa, greater than 1 Pa, greater than 10 Pa or
greater than 20 Pa.
[0094] Introducing high-aspect ratio particles into the treatment
fluid, e.g., particles having an aspect ratio of at least 6,
represents additional or alternative embodiments for stabilizing
the treatment fluid. Examples of such non-spherical particles
include, but are not limited to, fibers, flakes, discs, rods,
stars, etc., as described in, for example, U.S. Pat. No. 7,275,596,
US20080196896, which are hereby incorporated herein by reference.
In certain embodiments, introducing ciliated or coated proppant
into the treatment fluid may stabilize or help stabilize the
treatment fluid.
[0095] 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.
[0096] In some additional or alternative embodiment, the STS system
may have the benefit that the smaller particles in the voids of the
larger particles act as slip additives like mini-ball bearings,
allowing the particles to roll past each other without any
requirement for relatively large spaces between particles. This
property can be demonstrated in some embodiments by the flow of the
STS through a relatively small slot orifice with respect to the
maximum diameter of the largest particle mode of the STS, e.g., a
slot orifice less than 6 times the largest particle diameter,
without bridging at the slot, i.e., the slurry flowed out of the
slot has an SVF that is at least 90% of the SVF of the STS supplied
to the slot. In contrast, the slickwater technique requires a ratio
of perforation diameter to proppant diameter of at least 6, and
additional enlargement for added safety to avoid screen out usually
dictates a ratio of at least 8 or 10 and does not allow high
proppant loadings.
[0097] In embodiments, the flowability of the STS through narrow
flow passages such as perforations and fractures is similarly
facilitated, allowing a smaller ratio of perforation diameter
and/or fracture height to proppant size that still provides
transport of the proppant through the perforation and/or to the tip
of the fracture, i.e., improved flowability of the proppant in the
fracture, e.g., in relatively narrow fracture widths, and improved
penetration of the proppant-filled fracture extending away from the
wellbore into the formation. These embodiments provide a relatively
longer proppant-filled fracture prior to screenout relative to
slickwater or high-viscosity fluid treatments.
[0098] As used herein, the "minimum slot flow test ratio" refers to
a test wherein an approximately 100 mL slurry specimen is loaded
into a fluid loss cell with a bottom slot opened to allow the test
slurry to come out, with the fluid pushed by a piston using water
or another hydraulic fluid supplied with an ISCO pump or equivalent
at a rate of 20 mL/min, wherein a slot at the bottom of the cell
can be adjusted to different openings at a ratio of slot width to
largest particle mode diameter less than 6, and wherein the maximum
slot flow test ratio is taken as the lowest ratio observed at which
50 vol % or more of the slurry specimen flows through the slot
before bridging and a pressure increase to the maximum gauge
pressure occurs. In some embodiments, the STS has a minimum slot
flow test ratio less than 6, or less than 5, or less than 4, or
less than 3, or a range of 2 to 6, or a range of 3 to 5.
[0099] Because of the relatively low water content (high SVF) of
some embodiments of the STS, fluid loss from the STS may be a
concern where flowability is important and SVF should at least be
held lower than PVF, or considerably lower than PVF in some other
embodiments. In conventional hydraulic fracturing treatments, there
are two main reasons that a high volume of fluid and high amount of
pumping energy have to be used, namely proppant transport and fluid
loss. To carry the proppant to a distant location in a fracture,
the treatment fluid has to be sufficiently turbulent (slickwater)
or viscous (gelled fluid). Even so, only a low concentration of
proppant is typically included in the treatment fluid to avoid
settling and/or screen out. Moreover, when a fluid is pumped into a
formation to initiate or propagate a fracture, the fluid pressure
will be higher than the formation pressure, and the liquid in the
treatment fluid is constantly leaking off into the formation. This
is especially the case for slickwater operations. The fracture
creation is a balance between the fluid loss and new volume
created. As used herein, "fracture creation" encompasses either or
both the initiation of fractures and the propagation or growth
thereof. If the liquid injection rate is lower than the fluid loss
rate, the fracture cannot be grown and becomes packed off.
Therefore, traditional hydraulic fracturing operations are not
efficient in creating fractures in the formation.
[0100] In some embodiments of the STS herein where the SVF is high,
even a small loss of carrier fluid may result in a loss of
flowability of the treatment fluid, and in some embodiments it is
therefore undertaken to guard against excessive fluid loss from the
treatment fluid, at least until the fluid and/or proppant reaches
its ultimate destination. In embodiments, the STS may have an
excellent tendency to retain fluid and thereby maintain
flowability, i.e., it has a low leakoff rate into a porous or
permeable surface with which it may be in contact. According to
some embodiments of the current application, the treatment fluid is
formulated to have very good leakoff control characteristics, i.e.,
fluid retention to maintain flowability. The good leak control can
be achieved by including a leakoff control system in the treatment
fluid of the current application, which may comprise one or more of
high viscosity, low viscosity, a fluid loss control agent,
selective construction of a multi-modal particle system in a
multimodal fluid (MMF) or in a stabilized multimodal fluid (SMMF),
or the like, or any combination thereof.
[0101] As discussed in the examples below and as shown in FIG. 10,
the leakoff of embodiments of a treatment fluid of the current
application was an order of magnitude less than that of a
conventional crosslinked fluid. It should be noted that the leakoff
characteristic of a treatment fluid is dependent on the
permeability of the formation to be treated. Therefore, a treatment
fluid that forms a low permeability filter cake with good leakoff
characteristic for one formation may or may not be a treatment
fluid with good leakoff for another formation. Conversely, certain
embodiments of the treatment fluids of the current application form
low permeability filter cakes that have substantially superior
leakoff characteristics such that they are not dependent on the
substrate permeability provided the substrate permeability is
higher than a certain minimum, e.g., at least 1 mD.
[0102] In certain embodiments herein, the STS comprises a packed
volume fraction (PVF) greater than a slurry solids volume fraction
(SVF), and has a spurt loss value (Vspurt) less than 10 vol % of a
fluid phase of the stabilized treatment fluid or less than 50 vol %
of an excess fluid phase (Vspurt<0.50*(PVF-SVF), where the
"excess fluid phase" is taken as the amount of fluid in excess of
the amount present at the condition SVF=PVF, i.e., excess fluid
phase .dbd.PVF-SVF).
[0103] In some embodiments the treatment fluid comprises an STS
also having a very low leakoff rate. For example, the total leakoff
coefficient may be about 3.times.10.sup.-4 m/min.sup.1/2 (10.sup.-3
ft/min.sup.1/2) or less, or about 3.times.10.sup.-5 m/min.sup.1/2
(10.sup.-4 ft/min.sup.1/2) or less. As used herein, Vspurt and the
total leak-off coefficient Cw are determined by following the
static fluid loss test and procedures set forth in Section 8-8.1,
"Fluid loss under static conditions," in Reservoir Stimulation,
3.sup.rd Edition, Schlumberger, John Wiley & Sons, Ltd., pp.
8-23 to 8-24, 2000, in a filter-press cell using ceramic disks
(FANN filter disks, part number 210538) saturated with 2% KCl
solution and covered with filter paper and test conditions of
ambient temperature (25.degree. C.), a differential pressure of
3.45 MPa (500 psi), 100 ml sample loading, and a loss collection
period of 60 minutes, or an equivalent testing procedure. In some
embodiments of the current application, the treatment fluid has a
fluid loss value of less than 10 g in 30 min when tested on a core
sample with 1000 mD porosity. In some embodiments of the current
application, the treatment fluid has a fluid loss value of less
than 8 g in 30 min when tested on a core sample with 1000 mD
porosity. In some embodiments of the current application, the
treatment fluid has a fluid loss value of less than 6 g in 30 min
when tested on a core sample with 1000 mD porosity. In some
embodiments of the current application, the treatment fluid has a
fluid loss value of less than 2 g in 30 min when tested on a core
sample with 1000 mD porosity.
[0104] 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 embodiments, the low
fluid loss characteristic may be obtained by including a leak-off
control agent, such as, for example, particulated loss control
agents (in some embodiments less than 1 micron or 0.05-0.5
microns), graded PSD or multimodal particles, polymers, latex,
fiber, etc. As used herein, the terms leak-off control agent, fluid
loss control agent and similar refer to additives that inhibit
fluid loss from the slurry into a permeable formation.
[0105] As representative leakoff control agents, which may be used
alone or in a multimodal fluid, there may be mentioned latex
dispersions, water soluble polymers, submicron particulates,
particulates with an aspect ratio higher than 1, or higher than 6,
combinations thereof and the like, such as, for example,
crosslinked polyvinyl alcohol microgel. The fluid loss agent can
be, for example, a latex dispersion of polyvinylidene chloride,
polyvinyl acetate, polystyrene-co-butadiene; a water soluble
polymer such as hydroxyethylcellulose (HEC), guar, copolymers of
polyacrylamide and their derivatives; particulate fluid loss
control agents in the size range of 30 nm to 1 micron, such as
.gamma.-alumina, colloidal silica, CaCO.sub.3, SiO.sub.2, bentonite
etc.; particulates with different shapes such as glass fibers,
flakes, films; and any combination thereof or the like. Fluid loss
agents can if desired also include or be used in combination with
acrylamido-methyl-propane sulfonate polymer (AMPS). In embodiments,
the leak-off control agent comprises a reactive solid, e.g., a
hydrolysable material such as PGA, PLA or the like; or it can
include a soluble or solubilizable material such as a wax, an
oil-soluble resin, or another material soluble in hydrocarbons, or
calcium carbonate or another material soluble at low pH; and so on.
In embodiments, the leak-off control agent comprises a reactive
solid selected from ground quartz, oil soluble resin, degradable
rock salt, clay, zeolite or the like. In other embodiments, the
leak-off control agent comprises one or more of magnesium
hydroxide, magnesium carbonate, magnesium calcium carbonate,
calcium carbonate, aluminum hydroxide, calcium oxalate, calcium
phosphate, aluminum metaphosphate, sodium zinc potassium
polyphosphate glass, and sodium calcium magnesium polyphosphate
glass, or the like.
[0106] 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.
[0107] In certain embodiments herein, the STS may be prepared by
combining the particles, such as proppant if present and
subproppant, the carrier liquid and any additives to form a
proppant-containing treatment fluid; and stabilizing the
proppant-containing treatment fluid. The combination and
stabilization may occur in any order or concurrently in single or
multiple stages in a batch, semi-batch or continuous operation. For
example, in some embodiments, the base fluid may be prepared from
the subproppant particles, the carrier liquid and other additives,
and then the base fluid combined with the proppant.
[0108] The treatment fluid may be prepared on location, e.g., at
the wellsite when and as needed using conventional treatment fluid
blending equipment.
[0109] In some embodiment, there is provided a wellsite equipment
configuration for a land-based fracturing operation using the
principles disclosed herein. The proppant is contained in sand
trailers. Water tanks are arranged along one side of the operation
site. Hopper receives sand from the sand trailers and distributes
it into the mixer truck. Blender 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.
The final mixed and blended slurry, also called frac fluid, is then
transferred to the pump trucks, and routed at treatment pressure
through treating line to rig, 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.
[0110] In some embodiments, the wellsite equipment configuration
may be provided with the additional feature of delivery of
pump-ready treatment fluid delivered to the wellsite in trailers to
and further elimination of the mixer, hopper, and/or blender. In
some embodiments the treatment fluid is prepared offsite and
pre-mixed with proppant and other additives, or with some or all of
the additives except proppant, such as in a system described in
co-pending co-assigned patent applications with application Ser.
No. 13/415,025, filed on Mar. 8, 2012, and application Ser. No.
13/487,002, filed on Jun. 1, 2012, the entire contents of which are
incorporated herein by reference in their entireties. As used
herein, the term "pump-ready" should be understood broadly. In
certain embodiments, a pump-ready treatment fluid means the
treatment fluid is fully prepared and can be pumped downhole
without being further processed. In some other embodiments, the
pump-ready treatment fluid means the fluid is substantially ready
to be pumped downhole except that a further dilution may be needed
before pumping or one or more minor additives need to be added
before the fluid is pumped downhole. In such an event, the
pump-ready treatment fluid may also be called a pump-ready
treatment fluid precursor. In some further embodiments, the
pump-ready treatment fluid may be a fluid that is substantially
ready to be pumped downhole except that certain incidental
procedures are applied to the treatment fluid before pumping, such
as low-speed agitation, heating or cooling under exceptionally cold
or hot climate, etc.
[0111] In certain embodiments herein, for example in gravel
packing, fracturing and frac-and-pack operations, the STS comprises
proppant and a fluid phase at a volumetric ratio of the fluid phase
(Vfluid) to the proppant (Vprop) equal to or less than 3. In
embodiments, Vfluid/Vprop is equal to or less than 2.5. In
embodiments, Vfluid/Vprop is equal to or less than 2. In
embodiments, Vfluid/Vprop is equal to or less than 1.5. In
embodiments, Vfluid/Vprop is equal to or less than 1.25. In
embodiments, Vfluid/Vprop is equal to or less than 1. In
embodiments, Vfluid/Vprop is equal to or less than 0.75. In
embodiments, Vfluid/Vprop is equal to or less than 0.7. In
embodiments, Vfluid/Vprop is equal to or less than 0.6. In
embodiments, Vfluid/Vprop is equal to or less than 0.5. In
embodiments, Vfluid/Vprop is equal to or less than 0.4. In
embodiments, Vfluid/Vprop is equal to or less than 0.35. In
embodiments, Vfluid/Vprop is equal to or less than 0.3. In
embodiments, Vfluid/Vprop is equal to or less than 0.25. In
embodiments, Vfluid/Vprop is equal to or less than 0.2. In
embodiments, Vfluid/Vprop is equal to or less than 0.1. In
embodiments, Vfluid/Vprop may be sufficiently high such that the
STS is flowable. In some embodiments, the ratio
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.
[0112] Nota bene, the STS may optionally comprise subproppant
particles in the whole fluid which are not reflected in the
Vfluid/Vprop ratio, which is merely a ratio of the liquid phase
(sans solids) volume to the proppant volume. This ratio is useful,
in the context of the STS where the liquid phase is aqueous, as the
ratio of water to proppant, i.e., Vwater/Vprop. In contrast, the
"ppa" designation refers to pounds proppant added per gallon of
base fluid (liquid plus subproppant particles), which can be
converted to an equivalent volume of proppant added per volume of
base fluid if the specific gravity of the proppant is known, e.g.,
2.65 in the case of quartz sand embodiments, in which case 1
ppa=0.12 kg/L=45 mL/L; whereas "ppg" (pounds of proppant per gallon
of treatment fluid) and "ppt" (pounds of additive per thousand
gallons of treatment fluid) are based on the volume of the
treatment fluid (liquid plus proppant and subproppant particles),
which for quartz sand embodiments (specific gravity=2.65) also
convert to 1 ppg=1000 ppt=0.12 kg/L=45 mL/L. The ppa, ppg and ppt
nomenclature and their metric or SI equivalents are useful for
considering the weight ratios of proppant or other additive(s) to
base fluid (water or other fluid and subproppant) and/or to
treatment fluid (water or other fluid plus proppant plus
subproppant). The ppt nomenclature is generally used in embodiments
reference to the concentration by weight of low concentration
additives other than proppant, e.g., 1 ppt=0.12 g/L.
[0113] In embodiments, the proppant-containing treatment fluid
comprises 0.27 L or more of proppant volume per liter of treatment
fluid (corresponding to 720 g/L (6 ppg) in embodiments where the
proppant has a specific gravity of 2.65), or 0.36 L or more of
proppant volume per liter of treatment fluid (corresponding to 960
g/L (8 ppg) in embodiments where the proppant has a specific
gravity of 2.65), or 0.4 L or more of proppant volume per liter of
treatment fluid (corresponding to 1.08 kg/L (9 ppg) in embodiments
where the proppant has a specific gravity of 2.65), or 0.44 L or
more of proppant volume per liter of treatment fluid (corresponding
to 1.2 kg/L (10 ppg) in embodiments where the proppant has a
specific gravity of 2.65), or 0.53 L or more of proppant volume per
liter of treatment fluid (corresponding to 1.44 kg/L (12 ppg) in
embodiments where the proppant has a specific gravity of 2.65), or
0.58 L or more of proppant volume per liter of treatment fluid
(corresponding to 1.56 kg/L (13 ppg) in embodiments where the
proppant has a specific gravity of 2.65), or 0.62 L or more of
proppant volume per liter of treatment fluid (corresponding to 1.68
kg/L (14 ppg) in embodiments where the proppant has a specific
gravity of 2.65), or 0.67 L or more of proppant volume per liter of
treatment fluid (corresponding to 1.8 kg/L (15 ppg) in embodiments
where the proppant has a specific gravity of 2.65), or 0.71 L or
more of proppant volume per liter of treatment fluid (corresponding
to 1.92 kg/L (16 ppg) in embodiments where the proppant has a
specific gravity of 2.65).
[0114] As used herein, in some embodiments, "high proppant loading"
means, on a mass basis, more than 1.0 kg proppant added per liter
of whole fluid including any sub-proppant particles (8 ppa,), or on
a volumetric basis, more than 0.36 L proppant added per liter of
whole fluid including any sub-proppant particles, or a combination
thereof. In some embodiments, the treatment fluid comprises more
than 1.1 kg proppant added per liter of whole fluid including any
sub-proppant particles (9 ppa), or more than 1.2 kg proppant added
per liter of whole fluid including any sub-proppant particles (10
ppa), or more than 1.44 kg proppant added per liter of whole fluid
including any sub-proppant particles (12 ppa), or more than 1.68 kg
proppant added per liter of whole fluid including any sub-proppant
particles (14 ppa), or more than 1.92 kg proppant added per liter
of whole fluid including any sub-proppant particles (16 ppa), or
more than 2.4 kg proppant added per liter of fluid including any
sub-proppant particles (20 ppa), or more than 2.9 kg proppant added
per liter of fluid including any sub-proppant particles (24 ppa).
In some embodiments, the treatment fluid comprises more than 0.45 L
proppant added per liter of whole fluid including any sub-proppant
particles, or more than 0.54 L proppant added per liter of whole
fluid including any sub-proppant particles, or more than 0.63 L
proppant added per liter of whole fluid including any sub-proppant
particles, or more than 0.72 L proppant added per liter of whole
fluid including any sub-proppant particles, or more than 0.9 L
proppant added per liter of whole fluid including any sub-proppant
particles.
[0115] In some embodiments, the water content in the fracture
treatment fluid formulation is low, e.g., less than 30% by volume
of the treatment fluid, the low water content enables low overall
water volume to be used, relative to a slickwater fracture job for
example, to place a similar amount of proppant or other solids,
with low to essentially zero fluid infiltration into the formation
matrix and/or with low to zero flowback after the treatment, and
less chance for fluid to 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.
[0116] In embodiments where the fracturing treatment fluid also has
a low viscosity and a relatively high SVF, e.g., 40, 50, 60 or 70%
or more, the fluid can in some surprising embodiments be very
flowable (low viscosity) and can be pumped using standard well
treatment equipment. With a high volumetric ratio of proppant to
water, e.g., greater than about 1.0, these embodiments represent a
breakthrough in water efficiency in fracture treatments.
Embodiments of a low water content in the treatment fluid certainly
results in correspondingly low fluid volumes to infiltrate the
formation, and importantly, no or minimal flowback during fracture
cleanup and when placed in production. In the solid pack, as well
as on formation surfaces and in the formation matrix, water can be
retained due to a capillary and/or surface wetting effect. In
embodiments, the solids pack obtained from an STS with multimodal
solids can retain a larger proportion of water than conventional
proppant packs, further reducing the amount of water flowback. In
some embodiments, the water retention capability of the
fracture-formation system can match or exceed the amount of water
injected into the formation, and there may thus be no or very
little water flowback when the well is placed in production.
[0117] In some specific embodiments, the proppant laden treatment
fluid comprises an excess of a low viscosity continuous fluid
phase, e.g., a liquid phase, and a multimodal particle phase, e.g.
solids phase, comprising high proppant loading with one or more
proppant modes for fracture conductivity and at least one
sub-proppant mode to facilitate proppant injection. As used herein
an excess of the continuous fluid phase implies that the fluid
volume fraction in a slurry (1-SVF) exceeds the void volume
fraction (1-PVF) of the solids in the slurry, i.e., SVF<PVF.
Solids in the slurry in embodiments may comprise both proppant and
one or more sub-proppant particle modes. In embodiments, the
continuous fluid phase is a liquid phase.
[0118] In some embodiments, the STS is prepared by combining the
proppant and a fluid phase having a viscosity less than 300 mPa-s
(170 s.sup.-1, 25 C) to form the proppant-containing treatment
fluid, and stabilizing the proppant-containing treatment fluid.
Stabilizing the treatment fluid is described above. In some
embodiments, the proppant-containing treatment fluid is prepared to
comprise a viscosity between 0.1 and 300 mPa-s (170 s.sup.-1, 25 C)
and a yield stress between 1 and 20 Pa (2.1-42 lb.sub.f/ft.sup.2).
In some embodiments, the proppant-containing treatment fluid
comprises 0.36 L or more of proppant volume per liter of
proppant-containing treatment fluid (8 ppa proppant equivalent
where the proppant has a specific gravity of 2.6), a viscosity
between 0.1 and 300 mPa-s (170 s.sup.-1, 25 C), a solids phase
having a packed volume fraction (PVF) greater than 0.72, a slurry
solids volume fraction (SVF) less than the PVF and a ratio of
SVF/PVF greater than about 1-2.1*(PVF-0.72).
[0119] In some embodiments, e.g., for delivery of a fracturing
stage, the STS comprises a volumetric proppant/treatment fluid
ratio (including proppant and sub-proppant solids) in a main stage
of at least 0.27 L/L (6 ppg at sp.gr. 2.65), or at least 0.36 L/L
(8 ppg), or at least 0.44 L/L (10 ppg), or at least 0.53 L/L (12
ppg), or at least 0.58 L/L (13 ppg), or at least 0.62 L/L (14 ppg),
or at least 0.67 L/L (15 ppg), or at least 0.71 L/L (16 ppg).
[0120] In some embodiments, the hydraulic fracture treatment may
comprise an overall volumetric proppant/water ratio of at least
0.13 L/L (3 ppg at sp. gr. 2.65), or at least 0.18 L/L (4 ppg), or
at least 0.22 L/L (5 ppg), or at least 0.26 L/L (6 ppg), or at
least 0.38 L/L (8 ppg), or at least 0.44 L/L (10 ppg), or at least
0.53 L/L (12 ppg), or at least 0.58 L/L (13 ppg). Note that
subproppant particles are not a factor in the determination of the
proppant water ratio.
[0121] In some embodiments, e.g., a front-end stage STS, the slurry
comprises a stabilized solids mixture comprising a particulated
leakoff control system (which may include solid and/or liquid
particles, e.g., submicron particles, colloids, micelles, PLA
dispersions, latex systems, etc.) and a solids volume fraction
(SVF) of at least 0.4.
[0122] In some embodiments, e.g., a pad stage STS, the slurry
comprises viscosifier in an amount to provide a viscosity in the
pad stage of greater than 300 mPa-s, determined on a whole fluid
basis at 170 s.sup.-1 and 25.degree. C.
[0123] In some embodiments, e.g., a flush stage STS, the slurry
comprises a proppant-free slurry comprising a stabilized solids
mixture comprising a particulated leakoff control system (which may
include solid and/or liquid particles, e.g., submicron particles,
colloids, micelles, PLA dispersions, latex systems, etc.) and a
solids volume fraction (SVF) of at least 0.4. In other embodiments,
the proppant-containing fracturing stage may be used with a flush
stage comprising a first substage comprising viscosifier and a
second substage comprising slickwater. The viscosifier may be
selected from viscoelastic surfactant systems, hydratable gelling
agents (optionally including crosslinked gelling agents), and the
like. In other embodiments, the flush stage comprises an overflush
equal to or less than 3200 L (20 42-gal bbls), equal to or less
than 2400 L (15 bbls), or equal to or less than 1900 L (12
bbls).
[0124] In some embodiments, the proppant stage comprises a
continuous single injection of the STS free of spacers.
[0125] In some embodiments the STS comprises a total proppant
volume injected into the wellbore or to be injected into the
wellbore of at least 800 liters. In some embodiments, the total
proppant volume is at least 1600 liters. In some embodiments, the
total proppant volume is at least 3200 liters. In some embodiments,
the total proppant volume is at least 8000 liters. In some
embodiments, the total proppant volume is at least 80,000 liters.
In some embodiments, the total proppant volume is at least 800,000
liters. The total proppant volume injected into the wellbore or to
be injected into the wellbore is typically not more than 16 million
liters.
[0126] 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 embodiments herein, the treatment fluid is stabilized
and the operator can decide to resume and/or complete the fracture
operation, or to circulate the STS (and any proppant) out of the
well bore. By stabilizing the treatment fluid to practically
eliminate particle settling, the treatment fluid possesses the
characteristics of excellent proppant conveyance and transport even
when static.
[0127] Due to the stability of the treatment fluid in some
embodiments herein, the proppant will remain suspended and the
fluid will retain its fracturing properties during the time the
pumping is interrupted. In some embodiments herein, a method
comprises combining at least 0.36, at least 0.4, or at least 0.45 L
of proppant per liter of base fluid to form a proppant-containing
treatment fluid, stabilizing the proppant-containing treatment
fluid, pumping the STS, e.g., injecting the proppant-containing
treatment fluid into a subterranean formation and/or creating a
fracture in the subterranean formation with the treatment fluid,
stopping pumping of the STS thereby stranding the treatment fluid
in the wellbore, and thereafter resuming pumping of the treatment
fluid, e.g., to inject the stranded treatment fluid into the
formation and continue the fracture creation, and/or to circulate
the stranded treatment fluid out of the wellbore as an intact plug
with a managed interface between the stranded treatment fluid and a
displacing fluid. Circulating the treatment fluid out of the
wellbore can be achieved optionally using coiled tubing or a
workover rig, if desired, but in embodiments the treatment fluid
will itself suspend and convey all the proppant out of the wellbore
with high efficiency. In some embodiments, the method may include
managing the interface between the treatment fluid and any
displacing fluid, such as, for example, matching density and
viscosity between the treatment and displacing fluids, using a
wiper plug or pig, using a gelled pill or fiber pill or the like,
to prevent density and viscous instabilities.
[0128] In some embodiments, the treatment provides
production-related features resulting from a low water content in
the treatment fluid, such as, for example, less infiltration into
the formation and/or less water flowback. Formation damage occurs
whenever the native reservoir conditions are disturbed. A
significant source of formation damage during hydraulic fracturing
occurs when the fracturing fluids contact and infiltrate the
formation. Measures can be taken to reduce the potential for
formation damage, including adding salts to improve the stability
of fines and clays in the formation, addition of scale inhibitors
to limit the precipitation of mineral scales caused by mixing of
incompatible brines, addition of surfactants to minimize capillary
blocking of the tight pores and so forth. There are some types of
formation damage for which additives are not yet available to
solve. For example, some formations will be mechanically weakened
upon coming in contact with water, referred to herein as
water-sensitive formations. Thus, it is desirable to significantly
reduce the amount of water that can infiltrate the formation during
a well completion operation.
[0129] Very low water slurries and water free slurries according to
certain embodiments disclosed herein offer a pathway to
significantly reduce water infiltration and the collateral
formation damage that may occur. Low water STS minimizes water
infiltration relative to slick water fracture treatments by two
mechanisms. First, the water content in the STS can be less than
about 40% of slickwater per volume of respective treatment fluid,
and the STS can provide in some embodiments more than a 90%
reduction in the amount of water used per volume or weight of
proppant placed in the formation. Second, the solids pack in the
STS in embodiments including subproppant particles retains more
water than conventional proppant packs so that less water is
released from the STS into the formation.
[0130] After fracturing, water flowback plagues the prior art
fracturing operations. Load water recovery typically characterizes
the initial phase of well start up following a completion
operation. In the case of horizontal wells with massive hydraulic
fractures in unconventional reservoirs, 15 to 30% of the injected
hydraulic fracturing fluid is recovered during this start up phase.
At some point, the load water recovery rate becomes very low and
the produced gas rate high enough for the well to be directed to a
gas pipeline to market. We refer to this period of time during load
water recovery as the fracture clean up phase. It is normal for a
well to clean up for several days before being connected to a gas
sales pipeline. The flowback water must be treated and/or disposed
of, and delays pipeline production. A low water content slurry
according to embodiments herein can significantly reduce the volume
and/or duration, or even eliminate this fracture clean up phase.
Fracturing fluids normally are lost into the formation by various
mechanisms including filtration into the matrix, imbibition into
the matrix, wetting the freshly exposed new fracture face, loss
into natural fractures. A low water content slurry will become dry
with only a small loss of its water into the formation by these
mechanisms, leaving in some embodiments no or very little free
water to be required (or able) to flow back during the fracture
clean up stage. The advantages of zero or reduced flowback include
reduced operational cost to manage flowback fluid volumes, reduced
water treatment cost, reduced time to put well to gas sales,
reduction of problematic waste that will develop by injected waters
solubilizing metals, naturally occurring radioactive materials,
etc.
[0131] There have also been concerns expressed by the general
public that hydraulic fracturing fluid may find some pathway into a
potable aquifer and contaminate it. Although proper well
engineering and completion design, and fracture treatment execution
will prevent any such contamination from occurring, if it were to
happen by an unforeseen accident, a slickwater system will have
enough water and mobility in an aquifer to migrate similar to a
salt water plume. A low water STS in embodiments may have a 90%
reduction in available water per mass of proppant such that any
contact with an aquifer, should it occur, will have much less
impact than slickwater.
[0132] Subterranean formations are heterogeneous, with layers of
high, medium, and low permeability strata interlaced. A hydraulic
fracture that grows to the extent that it encounters a high
permeability zone will suddenly experience a high leakoff area that
will attract a disproportionately large fraction of the injected
fluid significantly changing the geometry of the created hydraulic
fracture possibly in an undesirable manner. A hydraulic fracturing
fluid that would automatically plug a high leakoff zone is useful
in that it would make the fracture execution phase more reliable
and probably ensure the fracture geometry more closely resembles
the designed geometry (and thus production will be closer to that
expected). One feature of embodiments of an STS is that it will
dehydrate and become an immobile mass (plug) upon losing more than
25% of the water it is formulated with. As an STS in embodiments
only contains up to 50% water by volume, then it will only require
a loss of a total of 12.5% of the STS treatment fluid volume in the
high fluid loss affected area to become an immobile plug and
prevent subsequent fluid loss from that area; or in other
embodiments only contains up to 40% water by volume, requiring a
loss of a total of 10% of the STS treatment fluid volume to become
immobile. A slick water system would need to lose around 90% or 95%
of its total volume to dehydrate the proppant into an immobile
mass.
[0133] Sometimes, during a hydraulic fracture treatment, the
surface treating pressure will approach the maximum pressure limit
for safe operation. The maximum pressure limit may be due to the
safe pressure limitation of the wellhead, the surface treating
lines, the casing, or some combination of these items. One common
response to reaching an upper pressure limit is to reduce the
pumping rate. However, with ordinary fracturing fluids, the
proppant suspension will be inadequate at low pumping rates, and
proppant may fail to get placed in the fracture. The stabilized
fluids in some embodiments of this disclosure, which can be highly
stabilized and practically eliminate particle settling, possess the
characteristic of excellent proppant conveyance and transport even
when static. Thus, some risk of treatment failure is mitigated
since a fracture treatment can be pumped to completion in some
embodiments herein, even at very low pump rates should injection
rate reduction be necessary to stay below the maximum safe
operating pressure during a fracture treatment with the stabilized
treatment fluid.
[0134] In some embodiments, the injection of the treatment fluid of
the current application can be stopped all together (i.e. at an
injection rate of 0 bbl/min). Due to the excellent stability of the
treatment fluid, very little or no proppant settling occurs during
the period of 0 bbl/min injection. Well intervention, treatment
monitoring, equipment adjustment, etc. can be carried out by the
operator during this period of time. The pumping can be resumed
thereafter. Accordingly, in some embodiments of the current
application, there is provided a method comprising injecting a
proppant laden treatment fluid into a subterranean formation
penetrated by a wellbore, initiating or propagating a fracture in
the subterranean formation with the treatment fluid, stopping
injecting the treatment fluid for a period of time, restarting
injecting the treatment fluid to continue the initiating or
propagating of the fracture in the subterranean formation.
[0135] In some embodiments, the treatment and system may achieve
the ability to fracture using a carbon dioxide proppant stage
treatment fluid. Carbon dioxide is normally too light and too thin
(low viscosity) to carry proppant in a slurry useful in fracturing
operations. However, in an STS fluid, carbon dioxide may be useful
in the liquid phase, especially where the proppant stage treatment
fluid also comprises a particulated fluid loss control agent. In
embodiments, the liquid phase comprises at least 10 wt % carbon
dioxide, at least 50 wt % carbon dioxide, at least 60 wt % carbon
dioxide, at least 70 wt % carbon dioxide, at least 80 wt % carbon
dioxide, at least 90 wt % carbon dioxide, or at least 95 wt %
carbon dioxide. The carbon dioxide-containing liquid phase may
alternatively or additionally be present in any pre-pad stage, pad
stage, front-end stage, flush stage, post-flush stage, or any
combination thereof.
[0136] Various jetting and jet cutting operations in embodiments
are significantly improved by the non-settling and solids carrying
abilities of the STS. Jet perforating and jet slotting are
embodiments for the STS, 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 can be used in
embodiments of the current application.
[0137] Drilling cuttings transport and cuttings stability during
tripping are also improved in embodiments. The STS can act to
either fracture the formation or bridge off cracks, depending on
the exact mixture used. The STS 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.
[0138] The modification of producing formations using explosives
and/or propellant devices in embodiments is improved by the ability
of the STS to move after standing stationary and also by its
density and stability.
[0139] Zonal isolations operations in embodiments are improved by
specific STS formulations optimized for leakoff control and/or
bridging abilities. Relatively small quantities of the STS
radically improve the sealing ability of mechanical and inflatable
packers by filling and bridging off gaps. Permanent isolation of
zones is achieved in some embodiments by bullheading low
permeability versions of the STS into water producing formations or
other formations desired to be isolated. Isolation in some
embodiments is improved by using a setting formulation of the STS,
but non-setting formulations can provide very effective permanent
isolation. Temporary isolation may be delivered in embodiments by
using degradable materials to convert a non-permeable pack into a
permeable pack after a period of time.
[0140] The pressure containing ability and ease of
placement/removal of sand plugs in embodiments are significantly
improved using appropriate STS formulations selected for high
bridging capacity. Such formulations will allow much larger gaps
between the sand packer tool and the well bore for the same
pressure capability. Another major advantage is the reversibility
of dehydration in some embodiments; a solid sand pack may be
readily re-fluidized and circulated out, unlike conventional sand
plugs.
[0141] In other embodiments, plug and abandon work may be improved
using CRETE cementing formulations in the STS and also by placing
bridging/leakoff controlling STS formulations below and/or above
cement plugs to provide a seal repairing material. The ability of
the STS 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.
[0142] This STS in other embodiments finds application in pipeline
cleaning to remove methane hydrates due to its carrying capacity
and its ability to resume motion.
[0143] Accordingly, the present invention provides the following
embodiments:
A. A method, comprising: [0144] placing a downhole completion
staging system or tool in a wellbore adjacent a subterranean
formation; [0145] operating the downhole completion staging system
or tool to establish one or more passages for fluid communication
between the wellbore and the subterranean formation in a plurality
of wellbore stages spaced along the wellbore; [0146] isolating one
or more of the wellbore stages for treatment; [0147] injecting a
stabilized slurry treatment fluid through the wellbore and the one
or more passages of the isolated wellbore stage into the
subterranean formation to place proppant in a fracture in the
subterranean formation; and repeating the isolation and proppant
placement for one or more additional stages. B. A method,
comprising: [0148] placing a downhole completion staging system or
tool in a wellbore adjacent a subterranean formation; [0149]
operating the downhole completion staging system or tool to
establish one or more passages for fluid communication between the
wellbore and the subterranean formation in a plurality of wellbore
stages spaced along the wellbore; [0150] isolating one or more of
the wellbore stages for treatment; [0151] injecting a treatment
fluid (which may or may not be a stabilized slurry) through the
wellbore and the one or more passages of the isolated wellbore
stage into the subterranean formation to place proppant in a
fracture in the subterranean formation; [0152] circulating a
stabilized slurry treatment fluid (which may or may not be the same
as the injected treatment fluid) through the isolated wellbore
stage to facilitate removal of proppant from the wellbore stage;
and [0153] repeating the isolation, proppant placement and
stabilized slurry treatment fluid circulation for one or more
additional stages. C. The method of embodiment B, wherein the
injected treatment fluid comprises a stabilized slurry treatment
fluid that may be the same as or different as the circulated
stabilized slurry treatment fluid. D. The method of any one of
embodiments A to C, comprising just-in-time perforating. E. A
method, comprising: [0154] placing a downhole completion staging
tool in a wellbore adjacent a subterranean formation; [0155]
operating the downhole completion staging tool to establish one or
more passages for fluid communication between the wellbore and the
subterranean formation in a plurality of wellbore stages spaced
along the wellbore; [0156] injecting a treatment fluid through the
wellbore and the one or more passages into the subterranean
formation to place proppant in a fracture in the subterranean
formation; [0157] moving the downhole completion staging tool away
from the one or more passages either before, during or after the
injection without removing the downhole completion staging tool
from the wellbore; [0158] deploying a diversion agent to block
further flow through the one or more passages; [0159] circulating a
stabilized slurry treatment fluid through the wellbore as the
injected treatment fluid or as a flush to facilitate removal of
proppant from the wellbore; and [0160] repeating the downhole
completion staging tool placement and operation, proppant
placement, downhole completion staging tool movement and stabilized
slurry treatment circulation for one or more additional stages. F.
The method of any one of embodiments A to E, wherein the placement
of the downhole completion staging system tool is tethered to a
string. G. The method of embodiment F, wherein the string comprises
a wireline assembly, pipe string or coiled tubing string. H. The
method of any one of embodiments A to G, wherein the downhole
completion staging system tool is translated within the wellbore
using the stabilized slurry treatment fluid as a transport medium.
I. The method of any one of embodiments A to H, wherein the
downhole completion staging system tool comprises a wireline tool
string comprising a blanking plug and perforating guns, and further
comprising setting the blanking plug in the wellbore, placing one
or more perforation clusters above the blanking plug, and
recovering the wireline tool string to the surface, wherein the
low-viscosity, stabilized slurry treatment fluid is circulated
through the wellbore into the formation to create the fracture,
place the proppant or a combination thereof. J. The method of any
one of embodiments A to H, wherein the downhole completion staging
system tool comprises a pipe or coiled tubing string comprising a
jetting assembly, and further comprising placing the jetting
assembly in the wellbore, closing an annulus around the string,
circulating abrasive materials down the string through the jetting
assembly to perforate a wellbore casing, wherein the low-viscosity,
stabilized slurry treatment fluid is circulated through the
annulus, perforations and into the formation to create the
fracture, place the proppant or a combination thereof. K. The
method of embodiment any one of embodiments A to H, further
comprising placing a production liner in the wellbore wherein the
production liner is fitted with a plurality of sliding sleeves in
the closed position, and inserting a sleeve-shifting device into a
capture feature on the downhole completion staging system tool to
open a fracturing port, wherein the low-viscosity, stabilized
slurry treatment fluid is circulated through the fracturing port
and into the formation to create the fracture, place the proppant
or a combination thereof. L. The method of embodiment K, further
comprising transporting the sleeve-shifting device within the
wellbore using the slurry treatment fluid as a transport medium,
wherein the transport medium is the same or different treatment
fluid with respect to the fracture creation treatment fluid or the
proppant placement treatment fluid. M. The method of any one of
embodiments A to L, further comprising circulating a plug-forming
slurry treatment fluid to form a temporary plug between at least
two stages. N. The method of embodiment M, further comprising
re-slurrying the plug following completion of the proppant
placement for the one stage to access another one of the one or
more additional stages for a subsequent isolation, fracture
creation, proppant placement and slurry treatment fluid circulation
for the additional one of the one or more stages. O. The method of
any one of embodiments A to N, wherein stabilized slurry treatment
fluid from one stage is circulated in the wellbore to another stage
to create the fracture, place the proppant or a combination
thereof. P. The method of any one of embodiments A to O, wherein
the stabilized slurry treatment fluids used in serial stages are
immediately preceded and/or followed by another stabilized slurry
pretreatment fluid not separated by a solids-free intervening
stage. Q. The method of any one of embodiments A to P, wherein the
downhole completion staging system tool is kept downhole within the
wellbore between serial stages. R. The method of any one of
embodiments A to O, further comprising circulating another
stabilized slurry treatment fluid through the wellbore between
stages to flush debris from the wellbore following completion of
one stage and prior to initiation of a serial stage, wherein the
flushing slurry treatment fluid may be the same or different
treatment fluid with respect to the fracture creation treatment
fluid or the proppant placement treatment fluid of either or both
of the immediately preceding or immediately subsequent stages. S.
The method of any one of embodiments A to R, wherein the stabilized
slurry treatment fluid comprises a slurry solids volume fraction
(SVF) greater than 0.6 and a slurry solids volume fraction (SVF)
less than the PVF. T. The method of any one of embodiments A to S,
wherein the stabilized slurry treatment fluid comprises a viscosity
less than 300 mPa-s (170 s.sup.-1, 25.degree. C.). U. The method of
embodiment T wherein the stabilized slurry treatment fluid
comprises a yield stress between 1 and 20 Pa (2.1-42
lb.sub.f/ft.sup.2). V. The method of either one of embodiments T
and U, wherein the stabilized treatment slurry fluid comprises 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). W. The method
of any one of embodiments A to V, wherein the stabilized slurry
treatment fluid comprises 0.36 L or more of proppant volume per
liter of proppant-containing treatment fluid (8 ppa proppant for a
proppant density of 2.65 g/mL). X. The method of any one of
embodiments A to W, further comprising: stopping circulation of the
stabilized slurry treatment fluid to thereby strand the treatment
fluid in the wellbore without solids settling; and thereafter
resuming circulation of the treatment fluid. Y. The method of any
one of embodiments A to X, further comprising stabilizing a
treatment fluid to form the stabilized treatment slurry fluid
meeting at least one of the following conditions: [0161] a. the
slurry has a low-shear viscosity equal to or greater than 1 Pa-s
(5.11 s-1, 25.degree. C.); [0162] b. the slurry has a
Herschel-Buckley (including Bingham plastic) yield stress (as
determined in the manner described herein) equal to or greater than
1 Pa; or [0163] c. the largest particle mode in the slurry has a
static settling rate less than 0.01 mm/hr; or [0164] d. 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 [0165] e. the
apparent dynamic viscosity (25.degree. C., 170 s-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 [0166] f. 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 [0167] g. 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. Z. The method of embodiment Y, wherein: 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-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. AA. The method of any one
of embodiments A to Z, wherein 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-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-1, 25.degree. C.); (5) a multimodal solids phase; (6)
a solids phase having a PVF greater than 0.7; (7) a viscosifier
selected from viscoelastic surfactants, in an amount ranging from
0.01 up to 7.2 g/L (60 ppt), and hydratable gelling agents in an
amount ranging from 0.01 up to 4.8 g/L (40 ppt) based on the volume
of fluid phase; (8) colloidal particles; (9) a particle-fluid
density delta less than 1.6 g/mL, (e.g., particles having a
specific gravity less than 2.65 g/mL, carrier fluid having a
density greater than 1.05 g/mL or a combination thereof); (10)
particles having an aspect ratio of at least 6; (11) ciliated or
coated proppant; and (12) combinations thereof. AB. The method of
any one of embodiments A to AA, wherein the stabilized slurry
comprises at least two of the stability indicia in AA. AC. The
method of any one of embodiments A to AB, wherein the stabilized
slurry comprises at least three of the stability indicia in AA. AD.
The method of any one of embodiments A to AC, wherein the
stabilized slurry comprises at least four of the stability indicia
in AA. AE. The method of any one of embodiments A to AD, wherein
the stabilized slurry comprises at least five of the stability
indicia in AA. AF. The method of any one of embodiments A to AE,
wherein the stabilized slurry comprises at least six of the
stability indicia in AA. AG. The method of any one of embodiments A
to AF, wherein the stabilized treatment slurry fluid is formed by
at least one of the following stabilization operations: (1)
introducing sufficient particles into the slurry or treatment fluid
to increase the SVF of the treatment fluid to at least 0.4; (2)
increasing a low-shear viscosity of the slurry or treatment fluid
to at least 1 Pa-s (5.11 s-1, 25.degree. C.); (3) increasing a
yield stress of the slurry or treatment fluid to at least 1 Pa; (4)
increasing apparent viscosity of the slurry or treatment fluid to
at least 50 mPa-s (170 s-1, 25.degree. C.); (5) introducing a
multimodal solids phase into the slurry or treatment fluid; (6)
introducing a solids phase having a PVF greater than 0.7 into the
slurry or treatment fluid; (7) introducing into the slurry or
treatment fluid a viscosifier selected from viscoelastic
surfactants, e.g., in an amount ranging from 0.01 up to 7.2 g/L (60
ppt), and hydratable gelling agents, e.g., in an amount ranging
from 0.01 up to 4.8 g/L (40 ppt) based on the volume of fluid
phase; (8) introducing colloidal particles into the slurry or
treatment fluid; (9) reducing a particle-fluid density delta to
less than 1.6 g/mL (e.g., introducing particles having a specific
gravity less than 2.65 g/mL, carrier fluid having a density greater
than 1.05 g/mL or a combination thereof); (10) introducing
particles into the slurry or treatment fluid having an aspect ratio
of at least 6; (11) introducing ciliated or coated proppant into
slurry or treatment fluid; and (12) combinations thereof. AH. The
method of any one of embodiments A to AG, wherein the stabilized
treatment slurry fluid is formed by at least two of the following
stabilization operations in AG. AI. The method of any one of
embodiments A to AH, wherein the stabilized treatment slurry fluid
is formed by at least three of the following stabilization
operations in AG. AJ. The method of any one of embodiments A to AI,
wherein the stabilized treatment slurry fluid is formed by at least
four of the following stabilization operations in AG. AK. The
method of any one of embodiments A to AJ, wherein the stabilized
treatment slurry fluid is formed by at least five of the following
stabilization operations in AG.
EXAMPLES
Example 1
Stabilized Treatment Slurry
[0168] An example of a stabilized treatment slurry (STS) is
provided in Table 1 below.
TABLE-US-00001 TABLE 1 STS Composition. Stabilized Stabilized
Proppant/ Proppant Free Solids Slurry Fluid components Slurry (g/L
of STS) (g/L of STS) Crystalline silica 40/70 mesh 0 900-1100
Crystalline silica 100 mesh 0 125-225 Crystalline silica 400 mesh
600-800 100-250 Calcium Carbonate.sup.1 2 micron 300-400 175-275
Water 150-250 150-250 Latex.sup.2 300-500 100-300 Dispersant.sup.3
2-4 2-4 Antifoam.sup.4 3-5 1-3 Viscosifier.sup.5 6-10 6-10
.sup.1Calcium Carbonate = SAFECARB 2 from MI-SWACO .sup.2Latex =
Styrene-Butadiene copolymer dispersion .sup.3Dispersant =
Polynaphthalene sulfonate .sup.4Antifoam = Silicone emulsion
.sup.5Viscosifier = AMPS/acrylamide copolymer solution
[0169] Excellent particle (proppant) suspension capability and very
low fluid loss were observed. The fluid leakoff coefficient was
determined by following the static fluid loss test and procedures
set forth in Section 8-8.1, "Fluid loss under static conditions,"
in Reservoir Stimulation, 3.sup.rd Edition, Schlumberger, John
Wiley & Sons, Ltd., pp. 8-23 to 8-24, 2000, in a filter-press
cell using ceramic disks (FANN filter disks, part number 210538)
saturated with 2% KCl solution and covered with filter paper, and
test conditions of ambient temperature (25.degree. C.), a
differential pressure of 3.45 MPs (500 psi), 100 ml sample loading,
and a loss collection period of 60 minutes, or an equivalent test.
The results are shown in FIG. 10. The total leakoff coefficient of
STS was determined to be very low from the test. The STS fluid loss
did not appear to be a function of differential pressure. This
unique low to no fluid loss property, and excellent stability (low
rate of solids settling), allows the STS to be pumped at a low rate
without concern of screen out.
Example 2
Stabilized Treatment Slurry
[0170] Another example of an STS is provided in Table 2 below,
which has an SVF of 60%. The fluid is very flowable and has been
pumped into a subterranean formation with available field
equipment. Typical slickwater operation has an SVF up to about 8%
only. In contrast, the fluid in the current example delivers
proppant at a much higher efficiency. It should be noted that not
all of the solids in these embodiments are conventional proppant,
and the 40/70 mesh proppant and 100 mesh sand are conventionally
referred to as proppant. In this regard, the SVF of the
conventional proppant in the total fluid is 44.2%, and the
volumetric ratio of proppant to fluid phase is quite high,
44.2/39.9=1.11. This represents a breakthrough in water efficiency
for proppant placement.
TABLE-US-00002 TABLE 2 STS Composition Components Wt % Vol % 40/70
proppant 49.7% 37.5% 100 mesh sand 8.9% 6.7% 30.mu. silica 8.9%
6.7% 2.mu. CaCO3 12.4% 9.2% Liquid Latex 9.8% 19.3% Water and
additives 10.3% 20.6%
[0171] A low total water content in the STS results from both high
proppant loading in the STS and the conversely relatively low
amount of free water required for the slurry to be
flowable/pumpable. Low water volume injection embodiments certainly
result in correspondingly low fluid volumes to flow back. It can
also be seen from the STS example in Table 2, the PVF of that
formulation is 69%. This means that only 31% of the volume is
fluid-filled voids. In a solid pack, a certain amount of water is
retained due to capillary and/or surface wetting effects. The
amount of retained water in this embodiment is higher than that of
a conventional proppant pack, further reducing the amount of water
flow back (in addition to inhibiting water infiltration into the
matrix). Considering the statistical amount of water flowed back
from a shale, carbonate or siltstone formation after a conventional
fracturing treatment, in embodiments of the STS fracturing
treatment the flow back is less than 30% or less than 20% or less
than 10% of the water injected in the STS stage and/or the total
water injected (including any pre-pad, pad, front-end, proppant,
flush, and post-flush stage(s)), and there is a good chance that
there may even be zero flow back.
[0172] As can be seen, to transport the same amount of proppant,
the amount of water required is significantly reduced. To deliver
45,000 kg (100,000 lb) of proppant, a conventional slickwater
treatment will require the use of 380 m.sup.3 (100,000 gallons) of
water assuming the average slickwater proppant concentration is
0.12 kg/L (1 ppa). On the contrary, to deliver the same amount of
proppant using the STS formulation of these embodiments, less than
11.3 m.sup.3 (3,000 gallons) of water are required, for a proppant
stage placement v/v efficiency of 150 percent (volume of proppant
placed is 1.5 times volume of water in proppant stage) versus 4.5
percent for the 1 ppa slickwater. The STS in this embodiment is
using only 3% of the water that is required using the slickwater
fracturing technique. Even considering any requirements of a pad, a
flush and other non-STS fluid, the amount of water used by STS in
this embodiment is still at least an order of magnitude less than
the comparable slickwater technique, e.g., less than 10% of the
water required for the slickwater technique. In embodiments, the
proppant stage placement v/v water efficiency (volume of
proppant/volume of water) is at least 10%, at least 20%, at least
30%, at least 40%, at least 50%, at least 60%, at least 70%, at
least 80%, at least 90%, at least 100%, at least 110%, or at least
120%, and in additional or alternative embodiments the aqueous
phase in the high-efficiency proppant stage has a viscosity less
than 300 mPa-s.
Example 3
STS Slurry Stability Tests
[0173] A slurry sample was prepared with the formulation given in
Table 3.
TABLE-US-00003 TABLE 3 STS Composition Components g/L Slurry 40/70
proppant 700-800 100 mesh sand 100-150 30.mu. silica 100-140 2.mu.
CaCO3 (SafeCARB2) 150-200 0.036 wt % Diutan solution 0.4-0.6 Water
and other additives 250-350
[0174] The slurry was prepared by mixing the water, diutan and
other additives, and SafeCARB particles in two 37.9-L (10 gallon)
batches, one in an eductor and one in a RUSHTON turbine, the two
batches were combined in a mortar mixer and mixed for one minute.
Then the sand was added and mixed one minute, silica added and
mixed with all components for one minute. A sample of the freshly
prepared slurry was evaluated in a Fann 35 rheometer at 25.degree.
C. with an R1B5F1 configuration at the beginning of the test with
speed ramped up to 300 rpm and back down to 0, an average of the
two readings at 3, 6, 100, 200 and 300 rpm (2.55, 5.10, 85.0, 170
and 255 s.sup.-1) recorded as the shear stress, and the yield
stress (.tau..sub.0) determined as the y-intercept using the
Herschel-Buckley rheological model.
[0175] The slurry was then placed and sealed with plastic in a 152
mm (6 in.) diameter vertical gravitational settling column filled
with the slurry to a depth of 2.13 m (7 ft). The column was
provided with 25.4-mm (1 in.) sampling ports located on the
settling column at 190 mm (6'3''), 140 mm (4'7''), 84 mm (2'9'')
and 33 mm (1'1'') connected to clamped tubing. The settling column
was mounted with a shaker on a platform isolated with four airbag
supports. The shaker was a BUTTKICKER brand low frequency audio
transducer. The column was vibrated at 15 Hz with a 1 mm amplitude
(vertical displacement) for two 4-hour periods the first and second
settling days, and thereafter maintained in a static condition for
10 days (12 days total settling time, hereinafter "8 h@15 Hz/10 d
static"). The 15 Hz/1 mm amplitude condition was selected to
correspond to surface transportation and/or storage conditions
prior to the well treatment.
[0176] At the end of the settling period the depth of any free
water at the top of the column was measured, and samples were
obtained, in order from the top sampling port down to the bottom.
The post-settling period samples were similarly evaluated in the
rheometer under the same configuration and conditions as the
initial slurry, and the Herschel-Buckley yield stress calculated.
The results are presented in Table 4.
TABLE-US-00004 TABLE 4 Rheological properties, initial and 8 h@15
Hz/10 d Dynamic-static aged samples Delta, @170 Shear Stress (Pa
(lbf/100 ft2)) Shear Rate 2.55 5.1 85 170 s.sup.-1 (%) (s.sup.-1):
Initial slurry 17.9 21.3 84.5 135 (base line) (37.4) (44.5) (176.4)
(282.7) Aged slurry, 8 h@15 Hz/10 d static Top sample 15.4 19.3
76.8 123 -8.9 (32.1) (40.4) (160.3) (257.1) Upper middle 15.9 20.2
81.9 132 -2.3 sample (33.3) (42.2) (171) (276.1) Lower middle 14.8
19.3 79.3 130 -3.7 sample (30.9) (40.4) (165.7) (271.4) Bottom
sample 18.6 22.7 89.6 146 +8.1 (38.9) (47.5) (187.1) (305.8)
[0177] Since the slurry showed no or low free water depth after
aging, the apparent viscosities (taken as the shear rate) of the
aged samples were all within 9% of the initial slurry, the slurry
was considered stable. Since none of the samples had an apparent
viscosity (calculated as shear rate/shear stress) greater than 300
mPa-s, the slurry was considered readily flowable. The carrier
fluid was deionized water. Slurries were prepared by mixing the
solids mixture and the carrier fluid. The slurry samples were
screened for mixability and the depth of any free water formed
before and after allowing the slurry to settle for 72 hours at
static conditions. Samples which could not be mixed using the
procedure described were considered as not mixable. The samples in
which more than 5% free water formed were considered to be
excessively settling slurries. The results were plotted in the
diagram seen in FIG. 9.
[0178] From the data seen in FIG. 9, stable, mixable slurries were
generally obtained where PVF is about 0.71 or more, the ratio of
SVF/PVF is greater than 2.1*(PVF-0.71), and, where PVF is greater
than about 0.81, SVF/PVF is less than 1-2.1*(PVF-0.81). These STS
systems were obtained with a low carrier fluid viscosity without
any yield stress. By increasing the viscosity of the carrier fluid
and/or using a yield stress fluid, an STS may be obtained in some
embodiments with a lower PVF and/or a with an SVF/PVF ratio less
than 1-2.1*(PVF-0.71).
Example 5
Slot Orifice Flow Data
[0179] The multimodal STS system has an additional benefit in these
embodiments in that the smaller particles in the voids of the
larger particles act as slip additives like mini-ball bearings,
allowing the particles to roll past each other without any
requirement for relatively large spaces between particles. This
property was demonstrated by the flow of the Table 2 STS
formulation of these embodiments through a small slot orifice. In
this experiment, the slurry was loaded into a cell with bottom slot
opened to allow fluid and solid to come out, and the fluid was
pushed by a piston using water as a hydraulic fluid supplied with
an ISCO pump at a rate of 20 mL/min. The slot at the bottom of the
cell was adjusted to different openings, 1.8 mm (0.0708 in.) and
1.5 mm (0.0591 in.). A few results of different slurries flowing
through the slots are shown in Table 5.
TABLE-US-00005 TABLE 5 Results of different slurries flowing
through different opening slots % slurry flowed % slurry flowed
through 1.8 mm through 1.5 mm Fluid (0.0708 in.) slot (0.0591 in.)
slot Slickwater with high ppa 20%* 0% 60% SVF STS 100% 50% 50% SVF
STS 100% 100% *The slurry flowed out of the cell has less solid
than what was left inside the cell, biggest particle in the
formulation is 267 microns (0.0105 in.).
[0180] It can be seen from the results that the passage of the STS
through the slot in this embodiment was facilitated, which
validates the flowability observation. With the larger slot the
ratio of slot width to largest proppant diameter was about 6.7; but
just 5.6 in the case of the smaller slot. The slickwater technique
requires a ratio of perforation diameter to proppant diameter of at
least 6, and additional enlargement for added safety to avoid
screen out usually dictates a ratio of at least 8 or 10 and does
not allow high proppant loadings. In embodiments, the flowability
of the STS through narrow flow passages (ratio of diameter of
proppant to diameter or width of flow passage less than 6, e.g.,
less than 5, less than 4 or less than 3 or a range of 2 to 6 or 3
to 5) such as perforations and fractures is similarly facilitated,
allowing a smaller ratio of perforation size to proppant size as
well as a narrower fracture that still provides transport of the
proppant to the tip, i.e., improved flowability of the proppant in
the fracture and improved penetration of the proppant-filled
fracture extending away from the wellbore into the formation. These
embodiments provide a relatively longer proppant-filled fracture
prior to screenout relative to slickwater or high-viscosity fluid
treatments.
Examples 6-9
Additional Formulations
[0181] Additional STS formulations were prepared as shown in Table
2. Example 6 was prepared without proppant and exemplifies a
high-solids stabilized slurry without proppant that can be used as
a treatment fluid, e.g., as a spacer fluid, pad or managed
interface fluid to precede or follow a proppant-containing
treatment fluid. Example 7 was similar to Example 6 except that it
contained proppant including 100 mesh sand. Example 8 was prepared
with gelling agent instead of latex. Example 9 was similar to
Example 8, but was prepared with dispersed oil particles instead of
calcium carbonate. Examples 7-9 exemplify treatment fluids suitable
for fracturing low mobility formations.
TABLE-US-00006 TABLE 6 STS Composition and Properties STS Example 6
Example 7 Example 8 Example 9 Components Size (.mu.m) Wt % Wt % Wt
% Wt % 40/70 proppant 210-400 -- 50-55 50-55 50-55 100 mesh sand
150 -- 8-12 8-12 8-12 Silica flour 28-33 40-45 6-12 6-12 6-12 CaCO3
2.5-3 20-25 8-12 8-12 -- Liquid Latex 0.18 20-25 8-12 -- --
Viscosifier -- 0.1-1 0.1-1 -- -- Anti-foam -- 0.05-0.5 0.05-0.5 --
-- Gelling agent -- -- -- 0.01-0.05 0.01-0.05 Dispersant --
0.05-0.5 0.05-0.5 0.05-0.5 -- Breaker -- -- -- 0.01-0.1 0.01-0.1
Breaker aid -- -- -- 0.005-0.05 0.005-0.05 Oil -- -- -- -- 2-3
Surfactant -- -- -- -- 0.1-1 Water -- 8-12 8-12 18-22 18-22
Rheology Yield Point (Pa) 11.5 8.9 15.3 13.5 K (Pa-s.sup.n) 5.41
3.09 1.42 2.39 n 0.876 0.738 0.856 0.725 Stability (static 72 h)
Stable Stable Stable Stable Leakoff control Cw (ft/min.sup.1/2)
0.0002 0.00015 0.003 0.0014 Filter cake (mm) ~1 <1 ~5 ~5 Clean
up ND ND 0.004-0.024 1-1.2 permeability (D) Fluid Properties SVF
(%) 40 (60*) 60 (70*) 60 54 (60*) Specific gravity 1.68 2 2 1.88
PPA (whole fluid) NA 14 14 13.6 Notes: ND = not determined NA = not
applicable *= including latex or oil
[0182] All of the fluids were stable, and had a yield point above
10 Pa and a viscosity less than 10 Pa-s. Rheological, leak-off
control and other fluid properties are given in Table 6.
[0183] While the disclosure has provided specific and detailed
descriptions to various embodiments, the same is to be considered
as illustrative and not restrictive in character. Only certain
example embodiments have been shown and described. Those skilled in
the art will appreciate that many modifications are possible in the
example embodiments without materially departing from the
disclosure. Accordingly, all such modifications are intended to be
included within the scope of this disclosure as defined in the
following claims.
[0184] 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