U.S. patent application number 14/313958 was filed with the patent office on 2015-12-24 for compound cluster placement in fractures.
The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to James Ernest Brown, Theodore Lafferty, Matthew J. Miller, Dmitriy Ivanovich Potapenko.
Application Number | 20150369029 14/313958 |
Document ID | / |
Family ID | 54869213 |
Filed Date | 2015-12-24 |
United States Patent
Application |
20150369029 |
Kind Code |
A1 |
Potapenko; Dmitriy Ivanovich ;
et al. |
December 24, 2015 |
COMPOUND CLUSTER PLACEMENT IN FRACTURES
Abstract
Proppant cluster placement in fractures with foamed carrying
fluid. A formation treatment method includes injecting a treatment
fluid stage, having a particulate-containing substage containing a
self-agglomerating solid composition and a foamed carrying fluid,
above a fracturing pressure, and alternating pulses of a pumping
parameter to transform the self-agglomerating composition into a
channelized solids pack, and closing the fracture. Also disclosed
are methods of modeling a fracture treatment interval for such a
method, and methods of treatment and systems to treat with such a
treatment fluid stage, wherein solid particulate-rich substages are
larger than the solid particulate-lean substages to form
particulate-rich island regions, an interconnected network of open
channel regions between the island regions and the island regions
are channelized to form particulate clusters within the island
regions separated from adjacent particulate clusters by open voids
in the island regions.
Inventors: |
Potapenko; Dmitriy Ivanovich;
(Sugar Land, TX) ; Brown; James Ernest; (Sugar
Land, TX) ; Lafferty; Theodore; (Sugar Land, TX)
; Miller; Matthew J.; (Katy, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Family ID: |
54869213 |
Appl. No.: |
14/313958 |
Filed: |
June 24, 2014 |
Current U.S.
Class: |
166/280.2 ;
166/177.5; 166/280.1 |
Current CPC
Class: |
C09K 8/80 20130101; E21B
43/267 20130101; C09K 8/703 20130101 |
International
Class: |
E21B 43/267 20060101
E21B043/267 |
Claims
1. A method to treat a subterranean formation penetrated by a
wellbore, comprising: providing a treatment fluid stage comprising
a particulate-containing substage comprising a self-agglomerating
solid composition and a foamed carrying fluid; injecting the
treatment fluid stage above a fracturing pressure to place the
treatment fluid stage in a fracture in the formation according to
pumping parameters selected from composition of the
particulate-containing substage and pumping rate of the treatment
fluid stage; alternating pulses of at least one of the pumping
parameters to transform the self-agglomerating solid composition in
the fracture into a channelized solids pack comprising clusters
having a high concentration of solids, wherein the clusters are
separated by open voids having a substantially reduced
concentration of solids between the clusters; and closing the
fracture onto the clusters.
2. The method of claim 1, wherein the self-agglomerating solids
composition comprises fiber.
3. The method of claim 1, wherein the transformation of the solid
composition comprises destabilization of the foamed carrying
fluid.
4. The method of claim 1, wherein the at least one alternated
pumping parameter comprises foam quality of the carrying fluid
between alternate pulses within the particulate-containing
substage.
5. The method of claim 1, wherein the at least one alternated
pumping parameter comprises foam quality of the carrying fluid
between alternate pulses within the particulate-containing
substage, wherein the foam quality (volume percent gas) is
alternated between values different by at least 5 percent.
6. The method of claim 1, wherein the at least one alternated
pumping parameter comprises a concentration between alternate
pulses within the particulate-containing substage of a fluid
rheology component [defined as anything that changes fluid
rheology, such as, for example, a viscosifier, breaker,
crosslinker, decrosslinker, etc. before closing the fracture.
7. The method of claim 1, wherein the at least one alternated
pumping parameter comprises a concentration of breaker between
alternate pulses, wherein the breaker reduces the viscosity of the
carrying fluid before closing the fracture.
8. The method of claim 1, wherein the at least one alternated
pumping parameter is selected from the group consisting of
crosslinker concentration, crosslinker delay agent concentration,
decrosslinker concentration, fiber concentration, proppant
concentration, fluid loss additive concentration, clay stabilizer
concentration, pH adjusting agent concentration, and combinations
thereof.
9. The method of claim 1, wherein closing the fracture comprises
shutting in the wellbore and waiting for the fracture to close.
10. The method of claim 1, wherein closing the fracture comprises
forced fracture closure.
11. The method of claim 1, wherein the treatment fluid stage
comprises alternating a plurality of the solid
particulate-containing substages with solid particulate-lean
substages, wherein a volume of each of the solid
particulate-containing substages is larger than a respective volume
of an adjacent one of the particulate-lean substages.
12. A fracture treatment method for a subterranean formation
penetrated by a wellbore, comprising: considering closure stress
and stiffness of an interval of the formation; modeling the
interval based on the closure stress and stiffness of the interval
to determine a minimum coverage of propped regions in a fracture in
the interval and maximum open channel breadth between the propped
regions to inhibit collapse of the open channels; formulating a
treatment fluid stage comprising alternating solid particulate-rich
and solid particulate-lean substages, wherein at least a portion of
the particulate-rich substage comprises a self-agglomerating solid
composition and a foamed carrying fluid, wherein a volume of each
of the particulate-rich substages is larger than a respective
volume of an adjacent one of the particulate-lean substages;
injecting the formulated treatment fluid stage above a fracturing
pressure into the formation by alternatingly injecting the solid
particulate-rich and solid particulate-lean substages into the
fracture; forming a plurality of particulate-rich island regions in
the fracture to provide at least the minimum coverage of propped
regions as determined by the modeling; forming an interconnected
network of open channel regions between the island regions in the
fracture having a channel breadth less than the maximum channel
breadth as determined by the modeling; reducing pressure in the
fracture to close the fracture propped on the island regions; and
hydraulically conducting fluid flow through the open channel
regions between the formation and the wellbore.
13. The method of claim 12, further comprising channelizing the
solid particulate rich island regions in situ in the fracture to
form solid particulate clusters within the island regions separated
from adjacent solid particulate clusters by open voids within the
island regions.
14. The method of claim 1, wherein the solid particulate-rich
substages and the solid particulate-lean substages in the treatment
stage fluid have an overall volumetric ratio from 60:40 to
95:5.
15. A method to treat a subterranean formation penetrated by a
wellbore, comprising: injecting a treatment fluid stage above a
fracturing pressure into the formation to distribute a mixture of a
solid particulate in a fracture; alternatingly injecting solid
particulate-rich and solid particulate-lean substages of the
treatment fluid stage into the fracture, wherein at least a portion
of the particulate-rich substage comprises a self-agglomerating
solid composition and a foamed carrying fluid, wherein a volume of
each of the solid particulate-rich substages is larger than a
respective volume of an adjacent one [immediately preceding or
following] of the solid particulate-lean substages to form a
plurality of solid particulate-rich island regions in the fracture
and an interconnected network of open channel regions between the
island regions; channelizing the particulate-rich island regions in
situ in the fracture to form particulate clusters within the island
regions separated from adjacent particulate clusters by open voids
in the island regions; reducing pressure in the fracture to close
the fracture onto the island regions; and hydraulically conducting
fluid flow through the open channel regions between the formation
and the wellbore.
16. The method of claim 15, wherein the solid particulate-rich
substages each comprise alternating pulses injected at different
rates.
17. The method of claim 15, wherein the solid particulate-rich
substages each comprise alternating pulses comprising a
substantially uniform distribution of one or more components in the
alternate pulses and a heterogeneous distribution between alternate
pulses of at least one other component.
18. The method of claim 15, wherein the particulate-rich substages
each comprise alternating pulses comprising a substantially uniform
distribution of one or more components in the alternate pulses, and
a heterogeneous distribution between alternate pulses of another
component selected from the solid particulate, foam quality (gas),
fibers, anchorant, agglomerant, agglomerant aid, agglomerant aid
activator, binding liquid, an induced settling trigger, viscous gel
macrostructures, and combinations thereof.
19. The method of claim 15, wherein the particulate-rich substages
each comprise alternating pulses comprising a substantially uniform
distribution of one or more components with respect to a liquid
phase of the carrying fluid in the alternate pulses, and a
heterogeneous distribution between alternate pulses of foam quality
(volume percent gas), wherein the foam quality is alternated
between values different by at least 5 percent.
20. The method of claim 15, wherein the carrying fluid comprises a
viscoelastic surfactant.
21. The method of claim 15, wherein the treatment fluid stage
comprises a pH control agent.
22. The method of claim 15, wherein the treatment fluid stage
comprises an ester and further comprising releasing an acid from
the ester.
23. The method of claim 15, wherein the solid particulate-lean
substages comprise fiber.
24. The method of claim 15, wherein the solid particulate-rich
substages comprise a slurry of the solid particulate freely
dispersed in fluid spaces around macrostructures [gel blobs or
fibers] suspended in a carrying fluid.
25. The method of claim 15, wherein the solid particulate-rich
substages and the solid particulate-lean substages in the treatment
stage fluid have an overall volumetric ratio from 60:40 to
95:5.
26. The method of claim 15, wherein the solid particulate-rich
substages provide at least a minimum coverage of propped regions
comprising the islands and a channel breadth between the propped
regions sufficiently small to inhibit collapse of the open channel
regions in the interconnected network.
27. A system to treat a fracture interval of a formation penetrated
by a wellbore, comprising: a subterranean formation penetrated by a
wellbore; a treatment fluid stage disposed at least partially in
the wellbore, the treatment fluid stage comprising solid
particulate-rich and solid particulate-lean substages, wherein a
volume of each of the solid particulate-rich substages is larger
than a respective volume of an adjacent one of the solid
particulate-lean substages to form a plurality of solid
particulate-rich island regions in the fracture and an
interconnected network of open channel regions between the island
regions; the solid particulate-rich substages each comprising
alternating pulses comprising a substantially uniform distribution
of one or more components with respect to a liquid phase of a
carrying fluid in the alternate pulses, and a heterogeneous foam
quality to channelize the particulate-rich island regions in situ
in the fracture to form particulate clusters within the island
regions separated from adjacent particulate clusters by open voids
within the island regions; a pump system to pump the treatment
fluid stage from the wellbore to the formation at a pressure above
fracturing pressure to inject the treatment fluid stage into a
fracture in the formation; and a shut in system to close the
fracture onto the solid particulate-rich island regions.
Description
RELATED APPLICATION DATA
[0001] None.
BACKGROUND
[0002] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0003] Fracturing is used to increase permeability of subterranean
formations. A fracturing fluid is injected into the wellbore
passing through the subterranean formation. A propping agent
(proppant) is injected into the fracture to maintain the distance
between the fracture walls upon closure and, thereby, to provide
hydraulic conductivity and improved extraction of extractive
fluids, such as oil, gas or water.
[0004] Heterogeneous placement of the proppant in clusters can
create conductive channels around the proppant clusters. The
improper placement of proppant particles before fracture closure,
however, can pose a risk of screenout in the wellbore or decrease
the conductivity in the fracture. For example, if the channels are
too wide and/or the proppant clusters of insufficient strength, the
fracture may collapse or the fracture width may be narrower than
needed for good conductivity; or if too much proppant is used the
channels may be too narrow and/or insufficiently interconnected for
good conductivity.
SUMMARY
[0005] The disclosed subject matter of the application in some
embodiments provides methods and systems to treat subterranean
formations penetrated by a wellbore using a compound cluster
placement technique.
[0006] In some embodiments according to the present disclosure, a
method to treat a subterranean formation penetrated by a wellbore
comprises providing a treatment fluid stage comprising a
particulate-containing substage comprising a self-agglomerating
solid composition and a foamed carrying fluid; injecting the
treatment fluid stage above a fracturing pressure to place the
treatment fluid stage in a fracture in the formation according to
pumping parameters selected from composition of the
particulate-containing substage and pumping rate of the treatment
fluid stage; alternating pulses of at least one of the pumping
parameters to transform the self-agglomerating solid composition in
the fracture into a channelized solids pack comprising clusters
having a high concentration of solids, wherein the clusters are
separated by open voids having a substantially reduced
concentration of solids between the clusters; and closing the
fracture onto the clusters.
[0007] In some embodiments, the self-agglomerating solids
composition comprises fiber. In some embodiments, the
transformation of the solid composition comprises destabilization
of the foamed carrying fluid. In some embodiments, the at least one
alternated pumping parameter comprises foam quality of the carrying
fluid between alternate pulses within the particulate-containing
substage, such as, for example, wherein the foam quality (volume
percent gas) is alternated between values different by at least 5
percent, e.g., 60% foam quality pulses alternated with 0% foam
quality (liquid carrying fluid only), e.g., where the composition
of one or more of solids and/or other components in the liquid
phase remains constant or continuous with respect to the liquid
phase.
[0008] In some embodiments, the at least one alternated pumping
parameter comprises a concentration between alternate pulses within
the particulate-containing substage of a fluid rheology component
[defined as anything that changes fluid rheology, such as, for
example, a viscosifier, breaker, crosslinker, decrosslinker, etc.
before closing the fracture, such as, for example, a concentration
of breaker between alternate pulses, e.g., wherein the breaker
reduces the viscosity of the carrying fluid before closing the
fracture. In some embodiments, the at least one alternated pumping
parameter is selected from the group consisting of crosslinker
concentration, crosslinker delay agent concentration, decrosslinker
concentration, fiber concentration, proppant concentration, fluid
loss additive concentration, clay stabilizer concentration, pH
adjusting agent concentration, and combinations thereof.
[0009] In some embodiments, closing the fracture comprises shutting
in the wellbore and waiting for the fracture to close, or forced
fracture closure.
[0010] In some embodiments, the treatment fluid stage comprises
alternating a plurality of the solid particulate-containing
substages with solid particulate-lean substages, wherein a volume
of each of the solid particulate-containing substages is larger
than a respective volume of an adjacent one of the particulate-lean
substages (e.g., the laden stage is larger than the smaller of the
immediately preceding or following clean stages to take
leading/trailing laden stages and ignore size of pad/flush
stages).
[0011] In some embodiments according to the present disclosure, a
method to treat a subterranean formation penetrated by a wellbore
comprises considering [defined as estimating or measuring] closure
stress and stiffness of an interval of the formation; modeling the
interval based on the closure stress and stiffness of the interval
to determine a minimum coverage of propped regions in a fracture in
the interval and maximum channel breadth between the propped
regions to inhibit collapse of the channels; formulating a
treatment fluid stage comprising alternating solid particulate-rich
and solid particulate-lean substages, wherein at least a portion of
the particulate-rich substage comprises a self-agglomerating solid
composition and a foamed carrying fluid, wherein a volume of each
of the particulate-rich substages is larger than a respective
volume of an adjacent one of the particulate-lean substages;
injecting the formulated treatment fluid stage above a fracturing
pressure into the formation by alternatingly injecting the solid
particulate-rich and solid particulate-lean substages into the
fracture; forming a plurality of particulate-rich island regions in
the fracture to provide at least the minimum coverage of propped
regions as determined by the modeling; forming an interconnected
network of open channel regions between the island regions in the
fracture having a channel breadth less than the maximum channel
breadth as determined by the modeling; reducing pressure in the
fracture to close the fracture propped on the island regions; and
hydraulically conducting fluid flow through the open channel
regions between the formation and the wellbore, e.g., producing
reservoir fluids or injecting a fluid into the reservoir.
[0012] In some embodiments, the method may further comprise
channelizing the solid particulate rich island regions in situ in
the fracture to form solid particulate clusters within the island
regions separated from adjacent solid particulate clusters by open
voids within the island regions. In some embodiments, the solid
particulate-rich substages and the solid particulate-lean substages
in the treatment stage fluid may have an overall volumetric ratio
from 60:40 to 95:5, or from 70:30 to 90:10.
[0013] In some embodiments according to the present disclosure, a
method comprises injecting a treatment fluid stage above a
fracturing pressure into the formation to distribute a mixture of a
solid particulate in a fracture; alternatingly injecting solid
particulate-rich and solid particulate-lean substages of the
treatment fluid stage into the fracture, wherein at least a portion
of the particulate-rich substage comprises a self-agglomerating
solid composition and a foamed carrying fluid, wherein a volume of
each of the solid particulate-rich substages is [at least 50%]
larger than a respective volume of an adjacent one [immediately
preceding or following] of the solid particulate-lean substages to
form a plurality of solid particulate-rich island regions in the
fracture and an interconnected network of open channel regions
between the island regions; channelizing the particulate-rich
island regions in situ in the fracture to form particulate clusters
within the island regions separated from adjacent particulate
clusters by open voids in the island regions; reducing pressure in
the fracture to close the fracture onto the island regions; and
hydraulically conducting fluid flow through the open channel
regions between the formation and the wellbore, e.g., producing
reservoir fluids or injecting a fluid into the reservoir.
[0014] In some embodiments, the solid particulate-rich substages
each comprise alternating pulses injected at different rates. In
some embodiments, the solid particulate-rich substages may each
comprise alternating pulses comprising a substantially uniform
distribution of one or more components in the alternate pulses and
a heterogeneous distribution between alternate pulses of at least
one other component, e.g., another component selected from the foam
quality (gas), solid particulate, fibers, anchorant, agglomerant,
agglomerant aid, agglomerant aid activator, binding liquid, an
induced settling trigger, viscous gel macrostructures, and
combinations thereof.
[0015] In some embodiments, the particulate-rich substages each
comprise alternating pulses comprising a substantially uniform
distribution of one or more components with respect to a liquid
phase of the carrying fluid in the alternate pulses, and a
heterogeneous distribution between alternate pulses of foam quality
(volume percent gas), wherein the foam quality is alternated
between values different by at least 5 percent.
[0016] In some embodiments, the carrying fluid comprises a
viscoelastic surfactant. In some embodiments, the treatment fluid
stage comprises a pH control agent. In some embodiments, the
treatment fluid stage comprises an ester and the method further
comprises releasing an acid from the ester. In some embodiments,
the solid particulate-lean substages comprise fiber. In some
embodiments, the solid particulate-rich substages comprise a slurry
of the solid particulate freely dispersed in fluid spaces around
macrostructures suspended in a carrying fluid.
[0017] In some embodiments, the solid particulate-rich substages
and the solid particulate-lean substages in the treatment stage
fluid have an overall volumetric ratio from 60:40 to 95:5, or from
70:30 to 90:10. In some embodiments, the solid particulate-rich
substages provide at least a minimum coverage of propped regions
comprising the islands and a channel breadth between the propped
regions sufficiently small to inhibit collapse of the open channel
regions in the interconnected network, e.g., a propped region:open
channel region areal ratio from 60:40 to 95:5, or from 70:30 to
90:10.
[0018] In some embodiments according to the present disclosure, a
system to treat a fracture interval of a formation penetrated by a
wellbore comprises: a subterranean formation penetrated by a
wellbore; a treatment fluid stage disposed at least partially in
the wellbore, the treatment fluid stage comprising solid
particulate-rich and solid particulate-lean substages, wherein a
volume of each of the solid particulate-rich substages is larger
(representing more than 50% of the total volume) than a respective
volume of an adjacent one (immediately preceding or following) of
the solid particulate-lean substages to form a plurality of solid
particulate-rich island regions in the fracture and an
interconnected network of open channel regions between the island
regions; the solid particulate-rich substages each comprising
alternating pulses comprising a substantially uniform distribution
of one or more components with respect to a liquid phase of a
carrying fluid in the alternate pulses, and a heterogeneous foam
quality to channelize the particulate-rich island regions in situ
in the fracture to form particulate clusters within the island
regions separated from adjacent particulate clusters by open voids
within the island regions; and a shut in system to close the
fracture onto the solid particulate-rich island regions.
[0019] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter.
BRIEF DESCRIPTION OF THE DRAWINGS
[0020] 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.
[0021] FIG. 1 schematically illustrates proppant distribution in a
fracture upon placement according to embodiments of the present
disclosure.
[0022] FIG. 2 schematically illustrates proppant distribution in
the fracture of FIG. 1 following heterogeneous settling according
to embodiments of the present disclosure.
[0023] FIG. 3 schematically illustrates a propped fracture having
proppant clusters separated by open voids within a propped region
of the fracture according to embodiments of the present
disclosure.
[0024] FIG. 4 illustrates a pumping sequence of a proppant-laden
substage with alternated foam quality according to embodiments of
the present disclosure.
[0025] FIG. 5 schematically illustrates a fracture filled with
alternating stages of homogenous proppant-rich and proppant-lean
treatment fluids.
[0026] FIG. 6 schematically illustrates a fracture filled with
alternating stages of in situ channelizing proppant-rich treatment
fluid and proppant-lean treatment fluid, wherein the volume of the
proppant rich treatment fluid is greater than that of the proppant
lean treatment fluid, according to embodiments of the present
disclosure.
[0027] FIG. 7 schematically illustrates a fracture filled with
alternating stages of in situ channelizing proppant-rich treatment
fluid and proppant-lean treatment fluid, wherein the volume of the
proppant rich treatment fluid is substantially greater than that of
the proppant lean treatment fluid, according to further embodiments
of the present disclosure.
[0028] FIG. 8 is a sectional view of a portion of the propped
fracture of FIG. 7 as seen along the view lines 8-8.
DETAILED DESCRIPTION OF SOME ILLUSTRATIVE EMBODIMENTS
[0029] 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.
[0030] 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.
[0031] As used herein, "embodiments" refers to non-limiting
examples of the application disclosed herein, whether claimed or
not, which may be employed or present alone or in any combination
or permutation with one or more other embodiments. Each embodiment
disclosed herein should be regarded both as an added feature to be
used with one or more other embodiments, as well as an alternative
to be used separately or in lieu of one or more other embodiments.
It should be understood that no limitation of the scope of the
claimed subject matter is thereby intended, any alterations and
further modifications in the illustrated embodiments, and any
further applications of the principles of the application as
illustrated therein as would normally occur to one skilled in the
art to which the disclosure relates are contemplated herein.
[0032] 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.
[0033] 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 instant disclosure.
[0034] In some embodiments according to the disclosure herein, an
in situ method and system are provided for increasing fracture
conductivity. By "in situ" is meant that channels of relatively
high hydraulic conductivity are formed between particulate clusters
in a fracture after at least a portion of the fracture has been
filled with a generally continuous proppant or other particle
concentration or regions of continuous proppant concentration. The
following discussion refers to proppant as one example of the first
solid particle which may be used in the present disclosure,
although other types of solid particles are contemplated. The terms
proppant and sand are used interchangeably herein.
[0035] The tern "self-agglomerating solid composition" refers to an
in situ treatment fluid system wherein a generally uniform region
or island of solids placed into a formation automatically coalesces
into proppant clusters within the region or island separated by
open voids between the clusters within the region nor island.
[0036] The term "foamed carrying fluid" is used interchangeably
with "energized fluid" and "foam" to refer to a fluid which when
subjected to a low pressure environment liberates or releases gas
from solution or dispersion, for example, a liquid containing
dissolved gases. Foams or energized fluids are stable mixtures of
gases and liquids that form a two-phase system. Foam and energized
fluids are generally described by their foam quality, i.e. the
ratio of gas volume to the foam volume (fluid phase of the
treatment fluid), i.e., the ratio of the gas volume to the sum of
the gas plus liquid volumes). If the foam quality is between 52%
and 95%, the energized fluid is usually called foam. Above 95%,
foam is generally changed to mist. In the present patent
application, the terms "foamed carrying fluid" and "energized
fluid" encompass both energized fluids and foams and refer to any
stable mixture of gas and liquid, regardless of the foam quality.
Foamed carrying fluids comprise any of: [0037] (a) Liquids that at
bottom hole conditions of pressure and temperature are close to
saturation with a species of gas. For example the liquid can be
aqueous and the gas nitrogen or carbon dioxide. Associated with the
liquid and gas species and temperature is a pressure called the
bubble point, at which the liquid is fully saturated. At pressures
below the bubble point, gas emerges from solution; [0038] (b)
Foams, consisting generally of a gas phase, an aqueous phase and a
solid phase. Additionally, the aqueous phase may have originated as
a solid material and once the gas phase is dissolved into the solid
phase, the viscosity of solid material is decreased such that the
solid material becomes a liquid; or [0039] (c) Liquefied gases.
[0040] As used herein, "destabilization" of a foamed fluid refers
to the formation of large gas bubbles, e.g., the coalescence of
fine gas bubbles into larger bubbles, which are incapable of
supporting any solid particles which may be present, resulting in
the formation of solid particle clusters adjacent to the bubbles.
In some embodiments, the foam quality can be used as a parameter to
adjust the destabilization rate of the treatment fluid, e.g.,
higher foam quality may lead to more destabilization and larger
proppant clusters, and/or alternating pulses of different foam
quality, e.g., pulses of 80% foam quality alternated with 75% foam
quality pulses, or 70% and 40%, or 50% and 0%, or the like, where
the liquid carrier fluid phase has an otherwise continuous
composition and proppant loading, may enable different proppant
settling rates between the adjacent pulses and a heterogeneous
proppant distribution, and thus a heterogeneous conductivity
distribution.
[0041] As used herein, a "hydraulically conductive fracture" is one
which has a high conductivity relative to the adjacent formation
matrix, whereas the term "conductive channel" refers to both open
channels as well as channels filled with a matrix having
interstitial spaces for permeation of fluids through the channel,
or channels filled with proppant islands of proppant clusters
wherein the proppant clusters are spaced apart by open voids
between the proppant clusters, such that the channel has a
relatively higher conductivity than adjacent non-channel areas.
[0042] As used herein, "compound cluster placement" refers to a
fracture system comprising proppant islands spaced apart by open
channels wherein the proppant islands are each comprised of a
plurality of proppant clusters, each proppant cluster comprising a
plurality of proppant particles in contact with adjacent particles,
wherein the spacing between the proppant clusters within a proppant
island is much less than the spacing between adjacent proppant
islands, e.g., an order of magnitude less. Proppant clusters may or
may not be porous, e.g., they may have a packed volume fraction
from 50 to 100% with interstitial flow paths on the order of the
largest particle size, whereas proppant islands in a compound
cluster placement system may each comprise a plurality of clusters
with intermediate sized flow channels or voids between the
clusters, which are generally smaller than the relatively larger
open flow cannels between the islands.
[0043] Proppant coverage refers to the area of a fracture along its
extent which contains the proppant islands or other propped regions
in relation to the total area of the extent of the fracture.
Because of the close proximity of the clusters within the islands
relative to the stiffness and closure stress, the entire area of
the island may be considered to be propped. The "channel breadth"
refers to the distance between the propped regions. Modeling tools
such as FracCADE (available from Schlumberger) or MATLAB are
available to determine, based on the closure stress, e.g., the
overburden pressure, and the stiffness or rigidity of the formation
at the fracture face, the maximum channel breadth that can be
tolerated before the fracture will collapse and opposing faces of
the fracture between the adjacent islands will be closed off. In
some embodiments, the treatment is designed to avoid collapse of
the channels, or to minimize risk of collapse, by providing open
channels between the proppant islands which generally do not exceed
the maximum allowable open channel breadth for the particular
fracture closure stress and stiffness.
[0044] The term "continuous" in reference to concentration or other
parameter as a function of another variable such as time, for
example, means that the concentration or other parameter is an
uninterrupted or unbroken function, which may include relatively
smooth increases and/or decreases with time, e.g., a smooth rate or
concentration of proppant particle introduction into a fracture
such that the distribution of the proppant particles is free of
repeated discontinuities and/or heterogeneities over the extent of
proppant particle filling. In some embodiments, a relatively small
step change in a function is considered to be continuous where the
change is within +/-10% of the initial function value, or within
+/-5% of the initial function value, or within +/-2% of the initial
function value, or within +/-1% of the initial function value, or
the like over a period of time of 1 minute, 10 seconds, 1 second,
or 1 millisecond. The term "repeated" herein refers to an event
which occurs more than once in a stage.
[0045] Conversely, a parameter as a function of another variable
such as time or rate, for example, is "discontinuous" wherever it
is not continuous, and in some embodiments, a repeated relatively
large step function change is considered to be discontinuous, e.g.,
where the lower one of the parameter values before and after the
step change is less than 80%, or less than 50%, or less than 20%,
or less than 10%, or less than 5%, or less than 2% or less than 1%,
of the higher one of the parameter values before and after the step
change over a period of time of 1 minute, 10 seconds, 1 second, or
1 millisecond.
[0046] In embodiments, the open voids between the clusters within
the proppant fill or proppant islands may be formed in situ after
placement of the proppant and/or proppant islands in the fracture
by differential movement of the proppant particles, e.g., by foam
destabilization, by coalescence of a binding liquid around the
agglomerant and/or proppant particles, by gravitational settling
and/or fluid movement such as fluid flow initiated by a flowback
operation, out of and/or away from an area(s) corresponding to the
conductive channel(s) and into or toward spaced-apart areas in
which clustering of the proppant particles results in the formation
of relatively less conductive areas, which clusters may correspond
to pillars between opposing fracture faces upon closure. In
embodiments, the movement of the proppant particles may be
facilitated by the presence or introduction of an agglomerant aid
such as a binding liquid, e.g., a hydrophobic liquid In
embodiments; and the movement of the proppant particles may
optionally be further facilitated by reduction of the viscosity of
the treatment fluid, which may be instantaneous, gradual, or
stagewise.
[0047] According to some embodiments herein, the open voids between
the clusters within the proppant islands or other regions of
proppant fill may be formed by injecting a treatment stage fluid,
comprising a slurry of a solid particulate freely dispersed in
fluid spaces around macrostructures suspended in a carrier fluid,
into the fracture and aggregating the solid particulate in the
fracture to form clusters at respective interfaces with adjacent
macrostructures. According to some embodiments, the solid
particulate comprises disaggregated proppant in a proppant-laden
substage or pulse within the substage. According to some
embodiments, the carrier fluid comprises fiber present in the fluid
spaces around the macrostructures, e.g., gel balls, to stabilize
the treatment stage fluid for the injection into the fracture.
[0048] In some embodiments, the method comprises pumping a proppant
laden fracturing fluid comprising a foamed carrying fluid into a
subterranean formation at pressure above a fracturing pressure of
the formation. With reference to the system illustrated in FIG. 1,
a pumping system 10 supplies a treatment fluid 12 to wellbore 14
and into the fracture 16. In this example, the treatment fluid 12
comprises a foamed proppant slurry, which initially fills the
fracture 16 with a generally homogenous distribution of a propping
agent. In some embodiments, the proppant slurry is destabilized,
for example, prior to closure of the fracture 16, as illustrated in
FIG. 2, resulting in the formation of proppant-rich clusters 18
separated by proppant-lean or proppant-free void spaces 20 between
the clusters. Where the fracturing fluid 12 comprises
macrostructures 22 such as fibers, these may dispose in the
clusters 18, the void spaces 20, or a combination thereof. As
illustrated in FIG. 3, upon closure of the fracture 16 and removal
of any fibers, e.g., by hydrolysis or other degradative pathway,
the clusters 18 prop open the fracture and fluid may readily flow
through the conductive void spaces 20.
[0049] As seen in FIG. 4, a pumping sequence used in some
embodiments has a continuous pumping rate 30, a continuous proppant
concentration 32 (with respect to the liquid carrier phase) and a
discontinuous foam quality 34, 36. In these embodiments, the
proppant loading may follow a proppant-free pad stage 38 beginning
at a relatively low proppant loading 40 which after one or more
foamed pulses 34A, may have a smooth ramp 42 up over a series of
foamed pulses 34B to a higher proppant loading 44, and then be
maintained at a constant rate 44 for an additional series of foamed
pulses 34C until the proppant stage 32 is ended, and followed by a
flush stage 46.
[0050] Alternatively, the pumping sequence used in some embodiments
may have a continuous pumping rate, a continuous proppant
concentration (with respect to the liquid carrier phase) and a
discontinuous rate for a gel breaking agent.
[0051] With reference to the system illustrated in FIG. 5, a
pumping system 10 supplies a treatment fluid 12 comprising a foamed
carrying fluid to wellbore 14 in communication with a fracture 16.
In this system the treatment fluid stage comprises alternating
proppant-laden substages 48, which may contain a foamed carrying
fluid, with a proppant-lean substage 50, which may or may not
comprise foamed carrying fluid, which form proppant islands 52 in
the fracture 16 corresponding to the proppant-laden substages 48
and channels 54 between the islands corresponding to the
proppant-lean substages 50.
[0052] During the injection of the fracturing fluid, the pressure
in the well or treatment zone thereof may be sufficiently
maintained to keep the fracture 16 from closing before the islands
52 and channels 54 are formed, following which the fracture is
closed on the proppant islands 52, which theoretically maintain the
spacing between the opposing fracture faces for hydraulic
conductivity. In this system, the channels 54 may be relatively
wide since the fracture 16 may have a high rigidity such that
fracture collapse does not occur, and thus a relatively high total
volume of the proppant-lean substages 50 may be employed relative
to that of the proppant-laden substages 52.
[0053] It should be noted when considering the relative volumes or
other properties of the proppant-laden substages 48 relative to the
proppant-lean substages 50, one generally refers only to the main
substages, that is, any preceding pad or pre-pad stages as well as
any following flush stages are not generally considered as being
either a proppant-laden substage 48 or a proppant-lean substage 50
and may be excluded from the calculation. For example, the initial
proppant-laden substage 48 is considered relative to the initial
trailing proppant-lean substage 50, whereas the ultimate
proppant-laden substage 48 may be considered relative to the
immediately preceding proppant-lean substage 50, and the
intermediate proppant-laden substages 48 may be considered relative
to either the immediately preceding or immediately following
proppant-lean substage 50.
[0054] In some embodiments according to the present disclosure as
seen in FIG. 6, the volume of the proppant-laden substages 48 is as
large as or larger than that of the adjacent proppant-lean
substages 50, which may result in a proportionately larger proppant
coverage by the proppant islands 56 in the fracture 16. The open
channels 58 between the islands 56 in some embodiments do not
exceed the maximum allowable channel breadth to inhibit collapse of
the fracture, while at the same time providing improved fracture
propping capability, e.g., a relatively wider fracture, due to the
higher propped region coverage, depending on the closure stress and
strength of the fracture rock. That is to say, the open channels 54
may have a narrow breadth relative to FIG. 5, but may also have a
greater width to maintain equivalent or improved conductivity, in
some embodiments.
[0055] In addition, in some embodiments the islands 56 in FIG. 6
may be comprised of a plurality of proppant clusters 60 and open
voids 62 to provide additional hydraulic conductivity through the
islands 56. In some embodiments, these proppant clusters may be
formed within the islands 56 by employing proppant-laden substages
48 which have an in-situ channelization functionality, e.g., a
pulsed foamed quality, pump rate or concentration of proppant or
other component such that clusters 60 of the proppant are formed
within the islands 56. For example, the proppant-laden substages 48
placed in the fracture 16 may include, activate, generate or
release a trigger that induces channelization; may be pulsed at
different rates to induce clustering of the proppant within the
islands 56; may contain alternating pulses comprising a
substantially uniform distribution of one or more components in the
alternate pulses and a heterogeneous distribution between alternate
pulses of at least one other component, e.g., another component
selected from the foam quality, solid particulate, fibers, breaking
agent, delayed viscosity reducing agent, anchorant, agglomerant,
agglomerant aid, agglomerant aid activator, binding liquid, an
induced settling trigger, viscous gel macrostructures, and
combinations thereof; or the like.
[0056] For some embodiments represented by FIGS. 7 and 8, the
volume of the proppant-laden substages 48 is substantially larger
than that of the adjacent proppant-lean substages 50, which results
in a substantially larger proppant coverage by the proppant islands
56 in the fracture 16. For example, solid particulate-rich
substages 48 and the solid particulate-lean substages 50 may have
an overall volumetric ratio from 60:40 to 95:5, or from 70:30 to
90:10, or the like, e.g., 80:20. Or, the relative volumes of the
proppant-laden substages 48 and proppant-lean substages 50 may be
such that the ratio of the proppant coverage (area of the islands
56) to that of the channels 58 is from 60:40 to 95:5, or from 70:30
to 90:10, or the like, e.g., 80:20.
[0057] In some embodiments, the movement of proppant into clusters
60 may be facilitated by the presence of the foamed carrying fluid
in the treatment fluid 12, especially in the proppant-laden
substages 48 and/or the proppant-lean substages 50, or by
activation of an optional trigger to destabilize the proppant-laden
substages 48 of the fracturing fluid and/or the regions of the
proppant islands 56, such as, for example, a breaker or
decrosslinking additive to at least partially reduce the localized
viscosity of the fracturing fluid, e.g., from a viscosity
corresponding to a crosslinked polymer to that of a linear polymer.
Agglomerants such as fibers may optionally also settle in the
fracture, e.g., at a slower rate than the proppant, which may
result in some embodiments from the agglomerants having a specific
gravity that is equal to or closer to that of the carrier fluid
than that of the proppant. As one non-limiting example, the
proppant may be sand with a specific gravity of 2.65, the
agglomerants may be a localized fiber-laden region comprising fiber
with a specific gravity of 1.1-1.5, e.g., polylactic acid fibers
having a specific gravity of 1.25, and the carrier fluid may be
aqueous with a specific gravity of 1-1.1.
[0058] In some embodiments settling of the proppant may also be
mediated by buoyancy imparted by gas, a binding liquid and/or
fibers, which may have a specific gravity lower than that of the
proppant, carrier liquid or other component. In this example, the
lower specific gravity component may have a lower settling rate
relative to the proppant. In other embodiments, agglomerants and/or
anchorants may interact with either or both of the fracture faces,
e.g. by friction or adhesion, which may similarly be mediated by
the presence of any binding liquid in some embodiments, e.g., where
the binding liquid has an affinity for the formation surface, and
may have a density similar or dissimilar to that of the proppant,
e.g., glass fibers may have a specific gravity greater than 2.
[0059] As a result of coalescence of proppant induced by
differential settling rates in the carrying fluid according to some
embodiments, the proppant may form clusters adjacent respective
agglomerants, facilitated by the presence of any binding liquid,
and settling is retarded. Further, in some embodiments, the
agglomerants may be anchorants which are activated to form
immobilized anchoring structures, which may be mediated by any
binding liquid, to hold the clusters fast against the opposing
surface(s) of the fracture.
[0060] In some embodiments, the method decreases the viscosity in
the proppant-laden substages 48 of the fracturing fluid and/or the
regions of the proppant islands 56 by employing a fracturing fluid
comprising a crosslinked polymeric viscosifier for proppant
placement, in one temporal stage to that of a linear gel, to
promote proppant/agglomerant/binding liquid agglomeration for
in-situ channelization, but without completely breaking the
viscosity to facilitate anchoring prior to fracture closure, i.e.,
the formation or activation of anchors to inhibit complete settling
of the proppant system to the floor of the fracture or proppant
island.
[0061] The in-situ channelization concept is based on the creation
of clusters, which in some embodiments may be anchored in the
fracture within the proppant islands, to promote open voids within
the islands. Anchors are materials designed to stay in place in the
fracture, while clusters are the agglomeration of sand and any
fiber, binding liquid or other materials that settle on top of the
anchors after placement but before fracture closure. To initiate
settling of the sand within the islands, a decrease in the fluid
viscosity is implemented in some embodiments. In some embodiments,
an acid or acid precursor may function as a de-crosslinker which
may be mixed homogenously in the treatment fluid or the
proppant-laden substages 48 thereof at the surface, or pulsed into
the proppant-laden substages 48, and pumped down the wellbore and
into the fracture. After placement, the de-crosslinker, which in
some embodiments may be based on ester chemistry to release the
acid by hydrolysis, is allowed to react with the crosslinked
polymer to reduce its viscosity. After fracture closure, a breaker
such as an oxidative breaker may break and/or, in the case of a
partially broken or decrosslinked viscosifier, continue to more
fully break the viscosifier to facilitate cleanup and reservoir
production.
[0062] In-situ channelization in some embodiments promotes high
conductivity through proppant islands 56 by the formation of open
void spaces 32, relying on the settlement of the proppant and
fibers on the anchors to form clusters, leaving high conductive
void spaces 32 within the proppant islands 56 that are free of
proppant surrounding the clusters 60. The rate of settlement of the
proppant is related to the creation of clusters 60, where a high
settling rate may lead to no anchors or clusters, whereas a slow
settling rate can lead to no open voids 62 due to premature
fracture closure. The settlement of the sand depends on the
viscosity and specific gravity of the fluid, and also, according to
embodiments herein, on the rate at which this viscosity decreases
at the reservoir temperature.
[0063] In one representative example according to some embodiments,
a gelling agent is guar based, crosslinked with borate or with a
delayed crosslinker and the oil-in-water emulsion employs alkaline
emulsifiers for stability, which may be destabilized by reducing
the pH. In some embodiments, the crosslinkers are used to create
highly viscous gels comprising a stable oil-in-water emulsion at a
pH between 8 and 12. In some embodiments, esters are used as dual
functionality demulsifiers and decrosslinkers, since at high
reservoir temperatures some esters can undergo hydrolysis and form
carboxylic acids, lowering the pH of the fluid and thus
destabilizing the emulsion to release the oil phase while
simultaneously deactivating the borate or other crosslinker and
thereby decrosslinking the fluid to improve mobility of the
agglomerants, anchorants, channelization aids and/or proppants.
[0064] A system used to implement the fracture treatment may
include a pump system comprising one or more pumps to supply the
treatment fluid to the wellbore and fracture. In embodiments, the
wellbore may include a substantially horizontal portion, which may
be cased or completed open hole, wherein the fracture is
transversely or longitudinally oriented and thus generally vertical
or sloped with respect to horizontal. A mixing station in some
embodiments may be provided at the surface to supply a mixture of
carrier fluid, proppant, agglomerant, agglomerant aid, agglomerant
aid activator, viscosifier, decrosslinking agent, etc., which may
for example be an optionally stabilized concentrated blend slurry
(CBS) to allow reliable control of the proppant concentration, any
fiber, agglomerant aid, etc., which may for example be a
concentrated masterbatch to allow reliable control of the
concentration of the fiber, proppant, agglomerant aid, etc., and
any other additives which may be supplied in any order, such as,
for example, other viscosifiers, loss control agents, friction
reducers, clay stabilizers, biocides, crosslinkers, breakers,
breaker aids, corrosion inhibitors, and/or proppant flowback
control additives, or the like.
[0065] In some embodiments, concentrations of one or more
additives, including the proppants, fibers, agglomerant aid,
breaker, viscosity reducing agent or the like, to the fracturing
fluid may be alternated. For example agglomerants/agglomerant aids
may be alternatingly added, or a higher agglomerant/agglomerant aid
concentration may be added, to form slugs of treatment fluid in
which agglomeration and/or settling is promoted or inhibited, which
may accumulate clusters during channelization, but which may be
completely degraded after fracture closure to widen open voids or
form additional open voids. Two or more additives (including
agglomerants and/or agglomerant aids) may also be alternated
independently in pulses within the proppant-laden substages.
[0066] The well may if desired also be provided with a shut in
valve to maintain pressure in the wellbore and fracture, a
flow-back/production line to flow back or produce fluids either
during or post-treatment, as well as any conventional wellhead
equipment.
[0067] If desired in some embodiments, the pumping schedule for the
proppant-laden substages may be employed according to the
alternating-proppant loading technology disclosed in U.S. Patent
Application Publication No. US 2008/0135242, which is hereby
incorporated herein by reference.
[0068] In some embodiments, a treatment slurry stage, e.g., the
proppant-laden substages thereof, has a continuous concentration of
a first solid particulate, e.g., proppant, and a discontinuous
concentration of an additive that facilitates either clustering of
the first solid particulate in the islands, or anchoring of the
clusters in the islands, or a combination thereof, to form clusters
of the first solid particulate to prop open the fracture upon
closure. As used herein, "anchorant" refers to a material, a
precursor material, or a mechanism, that inhibits movement such as
settling, or preferably stops movement, of particulates or clusters
of particulates in a fracture, whereas an "anchor" refers to an
anchorant that is active or activated to inhibit or stop the
movement. In some embodiments, the agglomerant may be an anchorant
that may comprise a material, such as fibers, flocs, flakes, discs,
rods, stars, etc., for example, which may be heterogeneously
distributed in the island regions of the fracture and have a
different movement rate, and/or cause some of the first solid
particulate to have a different movement rate, which may be faster
or preferably slower with respect to the settling of the first
solid particulate and/or clusters. As used herein, the term "flocs"
includes both flocculated colloids and colloids capable of forming
flocs in the treatment slurry stage.
[0069] In some embodiments, the agglomerant/anchorant may adhere to
one or both opposing surfaces of the fracture to stop movement of a
proppant particle cluster and/or to provide immobilized structures
upon which proppant or proppant cluster(s) may accumulate. In some
embodiments, the agglomerants/anchors may adhere to each other to
facilitate consolidation, stability and/or strength of the formed
clusters, which adherence may be mediated by the presence or
generation of any binding liquid. Adherence of the agglomerants to
each other and/or to the fracture surface may be promoted by a
binding liquid in some embodiments.
[0070] In some embodiments, the anchorant may comprise a continuous
concentration of a first anchorant component and a discontinuous
concentration of a second anchorant component, e.g., where the
first and second anchorant components may react or combine to form
the anchor as in a fiber/binding liquid system, a two-reactant
system, a catalyst/reactant system, a pH-sensitive reactant/pH
modifier system (which may be or include the decrosslinker), or the
like.
[0071] In some embodiments, the anchorant may form boundaries for
particulate movement, e.g., lower boundaries for particulate
settling.
[0072] In some embodiments, the conductive channels extend in fluid
communication from adjacent a face of the formation away from the
wellbore to or to near the wellbore, e.g., to facilitate the
passage of fluid between the wellbore and the formation, such as in
the production of reservoir fluids and/or the injection of fluids
into the formation matrix. As used herein, "near the wellbore"
refers to conductive channels coextensive along a majority of a
length of the fracture terminating at a permeable matrix between
the conductive channels and the wellbore, e.g., where the region of
the fracture adjacent the wellbore is filled with a permeable
solids pack as in a high conductive proppant tail-in stage, gravel
packing or the like.
[0073] In some embodiments, the proppant islands are channelized by
injecting into a fracture in the formation at a continuous rate the
proppant-laden substage with a continuous first solid particulate
concentration; and while maintaining the continuous rate and first
solid particle concentration during injection of the proppant-laden
substage, successively alternating concentration modes of an
anchorant, such as fiber, in pulses between a plurality of
relatively anchorant-rich modes and a plurality of anchorant-lean
modes within the injected treatment fluid stage.
[0074] In some embodiments, the injection of the proppant-laden
substages forms a homogenous region within the proppant islands of
continuously uniform distribution of the first solid particulate.
In some embodiments, the alternation of pulses of the concentration
of the agglomerant and/or agglomerant aid forms heterogeneous areas
within the proppant islands comprising agglomerant/agglomerant
aid-rich areas and agglomerant/agglomerant aid-lean areas.
[0075] In some embodiments, the agglomerant may comprise a
degradable material. In some embodiments, the agglomerant is
selected from the group consisting of polylactic acid (PLA),
polyglycolic acid (PGA), polyethylene terephthalate (PET),
polyester, polyamide, polycaprolactam and polylactone,
poly(butylene succinate, polydioxanone, glass, ceramics, carbon
(including carbon-based compounds), elements in metallic form,
metal alloys, wool, basalt, acrylic, polyethylene, polypropylene,
novoloid resin, polyphenylene sulfide, polyvinyl chloride,
polyvinylidene chloride, polyurethane, polyvinyl alcohol,
polybenzimidazole, polyhydroquinone-diimidazopyridine,
poly(p-phenylene-2,6-benzobisoxazole), rayon, cotton, or other
natural fibers, rubber, sticky fiber, or a combination thereof. In
some embodiments the agglomerant may comprise acrylic fiber. In
some embodiments the agglomerant may comprise mica.
[0076] In some embodiments, the agglomerant is present in the
agglomerant-laden stages or pulses of the proppant-laden substages
in an amount of less than 5 vol %. All individual values and
subranges from less than 5 vol % are included and disclosed herein.
For example, the amount of agglomerant may be from 0.05 vol % less
than 5 vol %, or less than 1 vol %, or less than 0.5 vol %. The
agglomerant may be present in an amount from 0.5 vol % to 1.5 vol
%, or in an amount from 0.01 vol % to 0.5 vol %, or in an amount
from 0.05 vol % to 0.5 vol %.
[0077] In further embodiments, the agglomerant may comprise a fiber
with a length from 1 to 50 mm, or more specifically from 1 to 10
mm, and a diameter of from 1 to 50 microns, or, more specifically
from 1 to 20 microns. All values and subranges from 1 to 50 mm are
included and disclosed herein. For example, the fiber agglomerant
length may be from a lower limit of 1, 3, 5, 7, 9, 19, 29 or 49 mm
to any higher upper limit of 2, 4, 6, 8, 10, 20, 30 or 50 mm. The
fiber agglomerant length may range from 1 to 50 mm, or from 1 to 10
mm, or from 1 to 7 mm, or from 3 to 10 mm, or from 2 to 8 mm. All
values from 1 to 50 microns are included and disclosed herein. For
example, the fiber agglomerant diameter may be from a lower limit
of 1, 4, 8, 12, 16, 20, 30, 40, or 49 microns to an upper limit of
2, 6, 10, 14, 17, 22, 32, 42 or 50 microns. The fiber agglomerant
diameter may range from 1 to 50 microns, or from 10 to 50 microns,
or from 1 to 15 microns, or from 2 to 17 microns.
[0078] In further embodiments, the agglomerant may be fiber
selected from the group consisting of polylactic acid (PLA),
polyester, polycaprolactam, polyamide, polyglycolic acid,
polyterephthalate, cellulose, wool, basalt, glass, rubber, or a
combination thereof.
[0079] In further embodiments, the agglomerant may comprise a fiber
with a length from 0.001 to 1 mm and a diameter of from 50
nanometers (nm) to 10 microns. All individual values from 0.001 to
1 mm are disclosed and included herein. For example, the
agglomerant fiber length may be from a lower limit of 0.001, 0.01,
0.1 or 0.9 mm to any higher upper limit of 0.009, 0.07, 0.5 or 1
mm. All individual values from 50 nanometers to 10 microns are
included and disclosed herein. For example, the fiber agglomerant
diameter may range from a lower limit of 50, 60, 70, 80, 90, 100,
or 500 nanometers to an upper limit of 500 nanometers, 1 micron, or
10 microns.
[0080] In some embodiments, the agglomerant may comprise an
expandable material, such as, for example, swellable elastomers,
temperature expandable particles, Examples of oil swellable
elastomers include butadiene based polymers and copolymers such as
styrene butadiene rubber (SBR), styrene butadiene block copolymers,
styrene isoprene copolymer, acrylate elastomers, neoprene
elastomers, nitrile elastomers, vinyl acetate copolymers and blends
of EVA, and polyurethane elastomers. Examples of water and brine
swellable elastomers include maleic acid grafted styrene butadiene
elastomers and acrylic acid grafted elastomers. Examples of
temperature expandable particles include metals and gas filled
particles that expand more when the particles are heated relative
to silica sand. In some embodiments, the expandable metals can
include a metal oxide of Ca, Mn, Ni, Fe, etc. that reacts with the
water to generate a metal hydroxide which has a lower density than
the metal oxide, i.e., the metal hydroxide occupies more volume
than the metal oxide thereby increasing the volume occupied by the
particle. Further examples of swellable inorganic materials can be
found in U.S. Application Publication Number US 20110098202, which
is hereby incorporated by reference in its entirety. An example for
gas filled material is EXPANCEL.TM. microspheres that are
manufactured by and commercially available from Akzo Nobel of
Chicago, Ill. These microspheres contain a polymer shell with gas
entrapped inside. When these microspheres are heated the gas inside
the shell expands and increases the size of the particle. The
diameter of the particle can increase 4 times which could result in
a volume increase by a factor of 64.
[0081] In some embodiments the agglomerants may be gel bodies such
as balls or blobs made with a viscosifier, such as for example, a
water soluble polymer such as polysaccharide like
hydroxyethylcellulose (HEC) and/or guar, copolymers of
polyacrylamide and their derivatives, and the like, e.g., at a
concentration of 1.2 to 24 g/L (10 to 200 ppt where "ppt" is pounds
per 1000 gallons of fluid), or a viscoelastic surfactant (VES). The
polymer in some embodiments may be crosslinked with a crosslinker
such as metal, e.g., calcium or borate. The gel bodies may further
optionally comprise fibers and/or particulates dispersed in an
internal phase. The gel bodies may be made from the same or
different polymer and/or crosslinker as the continuous crosslinked
polymer phase, but may have a different viscoelastic characteristic
or morphology.
[0082] In some embodiments the breaking agent may be a persulphate
such as ammonium persulphate, a bromate such as sodium bromate, a
chlorate or chlorite such as sodium chlorate and sodium chlorite,
or enzyme. Some viscosity reducing agents may be esters such as
ethyllactate, buthylglutarate, DBE esters et cetera or polyesters
such as PLA, PGA et cetera for borate x-linked fluids, lactates and
polylactate for Zr x-linked fluids, etc. Breakers or viscosity
reducing agents may be used in dissolved, solid and encapsulated
forms.
[0083] In some embodiments, a system to produce reservoir fluids
comprises the wellbore and the fracture resulting from any of the
fracturing methods disclosed herein.
[0084] The following discussion is based on specific examples
according to some embodiments wherein the first particulate
comprises proppant and the agglomerant or anchor, where present,
comprises fiber. In some specific embodiments illustrated below,
the wellbore is oriented horizontally and the fracture is generally
vertical, however, the disclosure herein is not limited to this
specific configuration.
[0085] 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, an energized fluid (including
foam), slurry, or any other form as will be appreciated by those
skilled in the art.
[0086] 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.
[0087] "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.
[0088] "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 gas or liquid 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 gas, liquid or solid 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.
[0089] The term "dispersion" means a mixture of one substance
dispersed in another substance, and may include colloidal or
non-colloidal systems. As used herein, "emulsion" generally means
any system with one liquid phase dispersed in another immiscible
liquid phase, and may apply to oil-in-water and water-in-oil
emulsions. Invert emulsions refer to any water-in-oil emulsion in
which oil is the continuous or external phase and water is the
dispersed or internal phase.
[0090] As used herein unless otherwise specified, as described in
further detail herein, particle size and particle size distribution
(PSD) mode refer to the median volume averaged size. The median
size used herein may be any value understood in the art, including
for example and without limitation a diameter of roughly spherical
particulates. In an embodiment, the median size may be a
characteristic dimension, which may be a dimension considered most
descriptive of the particles for specifying a size distribution
range.
[0091] As used herein, a "water soluble polymer" refers to a
polymer which has a water solubility of at least 5 wt % (0.5 g
polymer in 9.5 g water) at 25.degree. C.
[0092] 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.
[0093] 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, also referred to herein as the
carrier fluid or comprising the carrier fluid, 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 (e.g., nitrogen or methane), liquefied gas
(e.g., propane, butane, or the like), 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 and mixtures of hydratable gels
(e.g. gels containing polysaccharides such as guars and their
derivatives, xanthan and diutan and their derivatives, hydratable
cellulose derivatives such as hydroxyethylcellulose,
carboxymethylcellulose and others, polyvinyl alcohol and its
derivatives, 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.
[0094] 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, expandable, swellable, dissolvable,
deformable, meltable, sublimeable, or otherwise capable of being
changed in shape, state, or structure.
[0095] In an embodiment, the particle(s) is substantially round and
spherical. In an embodiment, 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) used as anchorants or
otherwise may have an aspect ratio of more than 2, 3, 4, 5 or 6.
Examples of such non-spherical particles include, but are not
limited to, fibers, flocs, flakes, discs, rods, stars, etc. All
such variations should be considered within the scope of the
current application.
[0096] 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 and inhibiting settling during proppant
placement, which can be removed, for example by dissolution or
degradation into soluble degradation products. Examples of such
non-spherical particles include, but are not limited to, fibers,
flocs, flakes, discs, rods, stars, etc., as described in, for
example, U.S. Pat. No. 7,275,596, US20080196896, which are hereby
incorporated herein by reference. In an embodiment, introducing
ciliated or coated proppant into the treatment fluid may also
stabilize or help stabilize the treatment fluid or regions thereof.
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.
[0097] In an embodiment, the particles may be multimodal. As used
herein multimodal refers to a plurality of particle sizes or modes
which each has a distinct size or particle size distribution, e.g.,
proppant and fines. As used herein, the terms distinct particle
sizes, distinct particle size distribution, or multi-modes or
multimodal, mean that each of the plurality of particles has a
unique volume-averaged particle size distribution (PSD) mode. That
is, statistically, the particle size distributions of different
particles appear as distinct peaks (or "modes") in a continuous
probability distribution function. For example, a mixture of two
particles having normal distribution of particle sizes with similar
variability is considered a bimodal particle mixture if their
respective means differ by more than the sum of their respective
standard deviations, and/or if their respective means differ by a
statistically significant amount. In an embodiment, the particles
contain a bimodal mixture of two particles; in an embodiment, the
particles contain a trimodal mixture of three particles; in an
embodiment, the particles contain a tetramodal mixture of four
particles; in an embodiment, the particles contain a pentamodal
mixture of five particles, and so on. Representative references
disclosing multimodal particle mixtures include U.S. Pat. No.
5,518,996, U.S. Pat. No. 7,784,541, U.S. Pat. No. 7,789,146, U.S.
Pat. No. 8,008,234, U.S. Pat. No. 8,119,574, U.S. Pat. No.
8,210,249, US 2010/0300688, US 2012/0000641, US 2012/0138296, US
2012/0132421, US 2012/0111563, WO 2012/054456, US 2012/0305245, US
2012/0305254, US 2012/0132421, WO2013085412 and US 20130233542,
each of which are hereby incorporated herein by reference.
[0098] "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.
[0099] "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. In some
embodiments, the proppant may be 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. In further embodiments, the
proppant may comprise particles or aggregates made from particles
with size from 0.001 to 1 mm. All individual values from 0.001 to 1
mm are disclosed and included herein. For example, the solid
particulate size may be from a lower limit of 0.001, 0.01, 0.1 or
0.9 mm to an upper limit of 0.009, 0.07, 0.5 or 1 mm. Here particle
size is defined is the largest dimension of the grain of said
particle.
[0100] "Gravel" refers to particles used in gravel packing, and the
term is synonymous with proppant as used herein. "Sub-proppant" or
"subproppant" refers to particles or particle size or mode
(including colloidal and submicron particles) having a smaller size
than the proppant mode(s); references to "proppant" exclude
subproppant particles and vice versa. In an embodiment, the
sub-proppant mode or modes each have a weight average mean particle
size less than or equal to about one-half of the weight average
mean particle size of a smallest one of the proppant modes, e.g., a
suspensive/stabilizing mode.
[0101] 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
greater than or equal to 2.8 g/mL, and/or the treatment fluid may
comprise an apparent specific gravity less than 1.5, less than 1.4,
less than 1.3, less than 1.2, less than 1.1, or less than 1.05,
less than 1, or less than 0.95, for example. In some embodiments a
relatively large density difference between the proppant and
carrier fluid may enhance proppant settling during the clustering
phase, for example.
[0102] 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 light/ultralight proppant from various manufacturers,
e.g., hollow proppant. 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. In some embodiments where the
proppant may be buoyant, i.e., having a specific gravity less than
that of the carrier fluid, the term "settling" shall also be
inclusive of upward settling or floating.
[0103] "Stable" or "stabilized" or similar terms refer to a
concentrated blend slurry (CBS) 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 CBS, and/or the slurry may
generally be regarded as stable over the duration of expected CBS
storage and use conditions, e.g., a CBS that passes a stability
test or an equivalent thereof. In an embodiment, stability can be
evaluated following different settling conditions, such as for
example static under gravity alone, or dynamic under a vibratory
influence, or dynamic-static conditions employing at least one
dynamic settling condition followed and/or preceded by at least one
static settling condition.
[0104] 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.
[0105] As used herein, a concentrated blend slurry (CBS) may meet
at least one of the following conditions: [0106] (1) the slurry has
a low-shear viscosity equal to or greater than 1 Pa-s (5.11
s.sup.-1, 25.degree. C.); [0107] (2) the slurry has a
Herschel-Bulkley (including Bingham plastic) yield stress (as
determined in the manner described herein) equal to or greater than
1 Pa; or [0108] (3) the largest particle mode in the slurry has a
static settling rate less than 0.01 mm/hr; or [0109] (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 [0110] (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 [0111] (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
[0112] (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.
[0113] In some embodiments, the concentrated blend 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.
[0114] In an embodiment, the concentrated blend 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.
[0115] Increasing carrier fluid viscosity in a Newtonian fluid also
proportionally increases the resistance of the carrier fluid
motion. In some embodiments, the carrier fluid has a lower limit of
apparent dynamic viscosity, determined at 170 s.sup.-1 and
25.degree. C., of 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, or at least about 500 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 1000 mPa-s, or 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 50 mPa-s.
In an embodiment, the fluid phase viscosity ranges from any lower
limit to any higher upper limit.
[0116] 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 an embodiment, the liquid phase
is essentially free of viscosifier or comprises a viscosifier in an
amount ranging from 0.01 up to 12 g/L (0.08-100 ppt) 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,
proppant settling in some embodiments may be triggered by breaking
the fluid using a breaker(s). In some embodiments, the slurry is
stabilized for storage and/or pumping or other use at the surface
conditions and proppant transport and placement, and settlement
triggering is achieved downhole at a later time prior to fracture
closure, which may be 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, any stabilizing particles (e.g., subproppant
particles) if present, a yield stress agent or characteristic,
and/or a activation of 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 to initiate destabilization of the slurry
and/or proppant settling, can be useful.
[0117] In embodiments, the fluid may include leakoff control
agents, such as, for example, 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, CaCO3, SiO2, bentonite etc.; particulates with different
shapes such as glass fibers, flocs, flakes, films; and any
combination thereof or the like. Fluid loss agents can if desired
also include or be used in combination with
acrylamido-methyl-propane sulfonate polymer (AMPS). In an
embodiment, the leak-off control agent comprises a reactive solid,
e.g., a hydrolyzable material such as PGA, PLA or the like; or it
can include a soluble or solubilizable material such as a wax, an
oil-soluble resin, or another material soluble in hydrocarbons, or
calcium carbonate or another material soluble at low pH; and so on.
In an embodiment, the leak-off control agent comprises a reactive
solid selected from ground quartz, oil soluble resin, degradable
rock salt, clay, zeolite or the like. In 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. The treatment fluid may also contain colloidal
particles, such as, for example, colloidal silica, which may
function as a loss control agent, gellant and/or thickener.
[0118] In embodiments, the proppant-containing treatment fluid may
comprise from 0.06 or 0.12 g of proppant per mL of treatment fluid
(corresponding to 0.5 or 1 ppa) up to 1.2 or 1.8 g/mL
(corresponding to 10 or 15 ppa). In some embodiments, the
proppant-laden treatment fluid may have a relatively low proppant
loading in earlier-injected fracturing fluid and a relatively
higher proppant loading in later-injected fracturing fluid, which
may correspond to a relatively narrower fracture width adjacent a
tip of the fracture and a relatively wider fracture width adjacent
the wellbore. For example, the proppant loading may initially begin
at 0.48 g/mL (4 ppa) and be ramped up to 0.6 g/mL (6 ppa) at the
end.
[0119] Accordingly, the present invention provides the following
embodiments: [Embodiments listing to be provided based on approved
claims]
EXAMPLES
Example 1
Foam Carrier Fluid Forming Uniform Clusters
[0120] The energized fluid as disclosed was tested at room
temperature, and atmospheric pressure, using artificial voids
created between two plates having a space there between. The
fracture width was 6 mm and the plates dimension were 100 cm by 100
cm. As would be understood, other sizes of plates could be used.
The plates were made from a transparent acrylic glass, so that the
settling and distribution of the treatment slurry may be observed
over time. 100 mesh sandpaper was glued to the back wall of the
slot to provide roughness.
[0121] In this example, a heterogeneous proppant distribution in
the slot was achieved by alternating pulses of a solid free foamed
fluid and laden foamed fluid. The solid free fluid contained 60 vol
% nitrogen and 40 vol % of 0.36% guar solution in water with 5 g/L
of polylactide fibers (length 6 mm, diameter 12 microns), 0.5% of
foaming agent (oxyalkylated alcohol), 2.4.times.10-5 g/ml of
potassium hydroxide, 0.5% of triethanolamine, 0.2 g/L of ammonium
persulfate. The fluid was crosslinked with 0.1% of potassium
borate. The laden fluid was of similar composition, 720 g of sand
of 20/40 mesh was added per liter of the foamed fluid (6 ppa).
Example 2
Foamed Carrier Fluid Forming Channels In Situ
[0122] In this example, a fracture was formed in a 37 m (120 ft)
interval in a formation having a closure stress of 14.5 MPa (2,100
psi) and a stiffness of 20,700 MPa (3.times.10.sup.6 psi).
Bottomhole static temperature was 70.degree. C. Using a FracCADE
7.4 modeling tool, it was determined that a propped region coverage
of 30% is required and a channel breadth of 1,000 mm can be
supported. The fracture treatment consisted of a pad stage of 31.8
m.sup.3 (200 bbls), proppant stages of 127.2 m.sup.3 (800 bbls) and
flush stage of 23.9 m.sup.3 (150 bbls) of water containing 2%
Potassium Chloride.
[0123] The placement was achieved by alternating 6.4 m.sup.3 (40
bbls) of proppant laden substages with 3.2 m.sup.3 (20 bbls) of
non-proppant substages. The proppant concentrations was increased
according to the following schedule of 130 g of proppant per liter
of carrier fluid (1 ppa), 260 g/L (2 ppa), 390 g/L (3 ppa), 520 g/L
(4 ppa). The increase of concentration was done every 31.8 m.sup.3
(200 bbls) of total fluid pumped (laden and clean stages). The
substages were pumped at a rate of 53 Usec (20 BPM).
[0124] The fluid used for the pad stage contained 60 vol % nitrogen
and 40 vol % of 3.6.times.10.sup.-3 g/ml of guar gum solution in
water, 3.6.times.10.sup.-5 g/ml of glycerol, 2.4.times.10.sup.-5
g/ml of potassium hydroxide, 7.3.times.10.sup.-5 g/ml of potassium
borate, 2.4.times.10.sup.-5 g/ml of oxyalkylated alcohol,
6.0.times.10.sup.-5 g/ml of tetramethyl ammonium chloride,
1.0.times.10.sup.-4 g/ml of triethanolamine and 1.2.times.10.sup.-4
g/ml of ammonium persulphate.
[0125] The carrier fluid contained 60 vol % nitrogen and 40 vol %
of 3.6.times.10.sup.-3 g/ml of guar gum solution in water,
3.6.times.10.sup.-5 g/ml of glycerol, 2.4.times.10.sup.-5 g/ml of
potassium hydroxide, 7.3.times.10.sup.-5 g/ml of potassium borate,
2.4.times.10.sup.-5 g/ml of oxyalkylated alcohol,
6.0.times.10.sup.-5 g/ml of tetramethyl ammonium chloride,
1.0.times.10.sup.-4 g/ml of triethanolamine,
1.2.times.10.sup.-4-3.6.times.10.sup.-4 g/ml of ammonium
persulphate, and polylactic acid fibers (length 6 mm, diameter 12
microns) into the fluid at 1.2.times.10.sup.-3 g/ml.
[0126] The proppant laden fluid had a similar composition
supplemented with sand of 20/40 mesh in concentration as mentioned
above.
[0127] Simulated bottomhole pressure was 17.6 MPa (2550 psi). This
pumping schedule and the used formulation were designed to meet the
minimum proppant coverage and maximum channel breadth determined by
the model.
[0128] While the embodiments have been illustrated and described in
detail in the drawings and foregoing description, the same is to be
considered as illustrative and not restrictive in character, it
being understood that only some embodiments have been shown and
described and that all changes and modifications that come within
the spirit of the embodiments are desired to be protected. It
should be understood that while the use of words such as ideally,
desirably, preferable, preferably, preferred, more preferred or
exemplary utilized in the description above indicate that the
feature so described may be more desirable or characteristic,
nonetheless may not be necessary and embodiments lacking the same
may be contemplated as within the scope of the invention, the scope
being defined by the claims that follow. 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.
* * * * *