U.S. patent application number 14/228295 was filed with the patent office on 2015-10-01 for well treatment.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Yiyan Chen, Oleg Kovalevsky, Hemant Ladva, Anthony Loiseau, Sergey Makarychev-Mikhailov, Giselle Refunjol.
Application Number | 20150275644 14/228295 |
Document ID | / |
Family ID | 54189608 |
Filed Date | 2015-10-01 |
United States Patent
Application |
20150275644 |
Kind Code |
A1 |
Chen; Yiyan ; et
al. |
October 1, 2015 |
WELL TREATMENT
Abstract
A method and system for increasing fracture conductivity. A
slurry, of a solid particulate freely dispersed in fluid spaces
around macrostructures suspended in a carrier fluid, is injected
into a fracture, the solid particulate is aggregated in the
fracture to form clusters, and the pressure reduced to prop the
fracture open on the clusters and form interconnected,
hydraulically conductive channels between the clusters. The system
comprises a subterranean formation, a treatment slurry stage
disposed in a wellbore penetrating the formation, and a pump system
to inject the treatment fluid stage into a fracture.
Inventors: |
Chen; Yiyan; (Sugar Land,
TX) ; Refunjol; Giselle; (Houston, TX) ;
Kovalevsky; Oleg; (Novosibirskaya Oblast, RU) ;
Makarychev-Mikhailov; Sergey; (Richmond, TX) ;
Loiseau; Anthony; (Rio de Janeiro, BR) ; Ladva;
Hemant; (Missouri City, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
54189608 |
Appl. No.: |
14/228295 |
Filed: |
March 28, 2014 |
Current U.S.
Class: |
166/308.1 ;
166/105; 166/308.2; 166/308.5 |
Current CPC
Class: |
C09K 8/80 20130101; E21B
43/267 20130101; C09K 2208/08 20130101; C09K 8/685 20130101; C09K
8/887 20130101 |
International
Class: |
E21B 43/267 20060101
E21B043/267; E21B 43/26 20060101 E21B043/26 |
Claims
1. A method for treating a subterranean formation penetrated by a
wellbore, comprising: 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 a
fracture in the formation; aggregating the solid particulate in the
fracture to form clusters at respective interfaces with adjacent
macrostructures; reducing pressure in the fracture to prop the
fracture open on the clusters and form interconnected,
hydraulically conductive channels between the clusters.
2. The method of claim 1, wherein the solid particulate comprises
disaggregated proppant and the treatment fluid stage is a
proppant-laden hydraulic fracturing fluid.
3. The method of claim 1, wherein the carrier fluid comprises fiber
present in the fluid spaces around the macrostructures to stabilize
the treatment stage fluid for the injection into the fracture.
4. The method of claim 1, further comprising viscosifying the
carrier fluid for injection into the formation, and breaking the
carrier fluid in the fracture to trigger the aggregation of the
solid particulate.
5. The method of claim 1, further comprising successively
alternating concentration modes of the macrostructures in the
treatment stage fluid between a relatively macrostructure-rich mode
and a macrostructure-lean mode during the treatment stage fluid
injection.
6. The method of claim 1, wherein the macrostructures comprise
viscous gel.
7. The method of claim 1, wherein the macrostructures comprise
viscous gel comprising crosslinked polymer.
8. The method of claim 1, wherein the macrostructures comprise
viscous gel comprising crosslinked polymer selected from
polysaccharides, polyacrylates, alginates, polyacrylamides, and
combinations thereof.
9. The method of claim 1, wherein the macrostructures comprise
viscous gel reinforced with proppant, subproppant, fiber or a
combination thereof.
10. The method of claim 1, further comprising degrading the
macrostructures after the aggregation of the solid particulate in
the fracture.
11. The method of claim 1, further comprising elongating the
macrostructures in the fracture.
12. The method of claim 1, wherein the macrostructures comprise a
gel relatively more viscous than the carrier fluid, and further
comprising elongating the macrostructures in the fracture by
restraining flow of the macrostructures in the fracture relative to
the carrier fluid, by compression of the macrostructures during
fracture closure, or by a combination thereof.
13. The method of claim 1, wherein the macrostructures comprise
viscous gel and further comprising compression and elongation of
the macrostructures during fracture closure to form gel-filled
channels comprising a plurality of the elongated macrostructures in
contact with each other.
14. The method of claim 1, wherein the macrostructures in the
injection comprise a volume in the treatment fluid from 5 to 30
volume percent [e.g. 15 vol %] and the solid particulate comprises
a volume in the treatment fluid from 95 to 70 volume percent [e.g.,
85 vol %], based on the total volume of the macrostructures and
solid particulate in the treatment fluid.
15. The method of claim 1, wherein the macrostructures have a
dimension at least 10 times larger than the solid particulate.
16. The method of claim 1, wherein the macrostructures comprise
long fibers having a length of at least about 0.75 cm.
17. The method of claim 1, wherein the macrostructures comprise
long fibers having a length of from about 1 cm to about 7.5 cm.
18. The method of claim 1, wherein the injection into the fracture
is at a continuous rate of the treatment fluid stage with a
continuous concentration of the solid particulate; and further
comprising, while maintaining the continuous rate and solid
particulate concentration during injection of the treatment fluid
stage, successively alternating concentration modes of the
macrostructures in the treatment fluid stage between a plurality of
relatively macrostructure-rich modes and a plurality of
macrostructure-lean modes.
19. The method of claim 1, wherein the injection of the treatment
fluid stage forms a homogenous region within the fracture of
continuously uniform distribution of the first solid particulate,
and wherein the alternation of the concentration modes of the
macrostructures forms heterogeneous areas within the fracture
comprising macrostructure-rich areas and macrostructure-lean
areas.
20. The method of claim 1, further comprising forming bridges with
the macrostructures in the fracture to retain the clusters.
21. The method of claim 1, wherein the macrostructures are selected
from a fiber, a floc, a flake, a ribbon, a platelet, a rod, or a
combination thereof.
22. The method of claim 1, wherein the macrostructures are selected
from the group consisting of polylactic acid (PLA), polyglycolic
acid (PGA), polyethylene terephthalate (PET), polyester, polyamide,
polycaprolactam and polylactone, poly(butylene succinate),
polydioxanonepolylactic acid, polyester, polycaprolactam,
polyamide, polyglycolic acid, polyterephthalate, or a combination
thereof.
23. The method of claim 1, wherein the macrostructures are long
fibers selected from the group consisting of 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, cellulose, wool, basalt, glass, rubber, acrylic,
mica, and combinations thereof.
24. The method of claim 1, wherein the macrostructures comprise
sticky fiber.
25. The method of claim 1, wherein the macrostructures are
degradable and further comprising degrading the macrostructures
after closure of the fracture.
26. A system, comprising: a subterranean formation penetrated by a
wellbore; a treatment slurry stage disposed in the wellbore, the
treatment slurry stage comprising a slurry of a solid particulate
freely dispersed in fluid spaces around macrostructures suspended
in a carrier fluid; and a pump system to inject 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.
27. The system of claim 26, wherein the solid particulate comprises
disaggregated proppant and the treatment fluid stage is a
proppant-laden hydraulic fracturing fluid.
28. The system of claim 26, wherein the carrier fluid comprises
fiber present in the fluid spaces around the macrostructures to
stabilize the treatment stage fluid for the injection into the
fracture.
29. The system of claim 26, wherein the treatment slurry stage
further comprises a viscosifier in the carrier fluid and a breaker
to break the carrier fluid in the fracture to trigger the
aggregation of the solid particulate.
30. The system of claim 26, wherein the treatment slurry stage
further comprises successively alternating concentration modes of
the macrostructures in the treatment slurry stage between a
relatively macrostructure-rich mode and a macrostructure-lean mode
during the treatment slurry stage injection.
31. The system of claim 26, wherein the macrostructures comprise
viscous gel.
32. The system of claim 26, wherein the macrostructures comprise
viscous gel comprising crosslinked polymer.
33. The system of claim 26, wherein the macrostructures comprise
viscous gel comprising crosslinked polymer selected from
polysaccharides, polyacrylates, alginates, polyacrylamides, and
combinations thereof.
34. The system of claim 26, wherein the macrostructures comprise
viscous gel reinforced with proppant, subproppant, fiber or a
combination thereof.
35. The system of claim 26, wherein the macrostructures comprise a
gel relatively more viscous than the carrier fluid.
36. The system of claim 26, wherein the macrostructures comprise a
volume in the treatment slurry stage from 5 to 30 volume percent
[e.g. 15 vol %] and the solid particulate comprises a volume in the
treatment slurry stage from 95 to 70 volume percent [e.g., 85 vol
%], based on the total volume of the macrostructures and solid
particulate in the treatment slurry stage.
37. The system of claim 26, wherein the macrostructures have a
dimension at least 10 times larger than the solid particulate.
38. The system of claim 26, wherein the macrostructures comprise
long fibers having a length of at least about 0.75 cm.
39. The system of claim 26, wherein the macrostructures comprise
long fibers having a length of from about 1 cm to about 7.5 cm.
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 create conductive pathways in a
subterranean formation and increase fluid flow between the
formation and the wellbore. A fracturing fluid is injected into the
wellbore passing through the subterranean formation. A propping
agent (proppant) is injected into the fracture to prevent fracture
closure and, thereby, to provide improved extraction of extractive
fluids, such as oil, gas or water.
[0004] The proppant maintains the distance between the fracture
walls in order to create conductive channels in the formation. The
pulsed injection of alternating proppant-free and fiber-stabilized,
proppant-laden slugs into the fracture has been used to obtain a
heterogeneous distribution of proppant particles into a channels
and pillars configuration, which can improve the conductivity in
the fracture. Accordingly, there is a demand for further
improvements in this area of technology.
SUMMARY
[0005] In some embodiments according to the disclosure herein, an
in situ method and system are provided for increasing fracture
conductivity. In embodiments, a method for treating a subterranean
formation penetrated by a wellbore may comprise: 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 a fracture in the formation; aggregating
the solid particulate in the fracture to form clusters at
respective interfaces with adjacent macrostructures; and reducing
pressure in the fracture to prop the fracture open on the clusters
and form interconnected, hydraulically conductive channels between
the clusters. In some embodiments, the macrostructures may be or
comprise long fibers, gel bodies or the like. In some embodiments,
the macrostructures may comprise gel bodies comprising an internal
phase(s) of a fiber, solid particulate, or the like.
[0006] In some embodiments, a system to produce reservoir fluids
comprises the wellbore and fracture resulting from any of the
fracturing methods disclosed herein.
[0007] In embodiments, a system comprises: a subterranean formation
penetrated by a wellbore; a treatment slurry stage disposed in the
wellbore, the treatment slurry stage comprising a slurry of a solid
particulate freely dispersed in fluid spaces around macrostructures
suspended in a carrier fluid; and a pump system to inject 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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] 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.
[0009] FIG. 1A is a schematic diagram of a fracture filled with
proppant and elongated macrostructures according to some
embodiments of the current application.
[0010] FIG. 1B is a schematic diagram of the proppant settlement
into clusters in the fracture of FIG. 1A according to some
embodiments of the current application.
[0011] FIG. 1C is a schematic diagram showing a cross sectional
elevation of the fracture of FIG. 1B as seen along the view lines
1C-1C according to some embodiments of the current application.
[0012] FIG. 2A is a schematic diagram of a fracture uniformly
filled with proppant and gel macrostructures according to some
embodiments of the current application.
[0013] FIG. 2B is a schematic diagram of the proppant settlement in
the fracture of FIG. 2A according to some embodiments of the
current application.
[0014] FIG. 2C is a schematic diagram of the conductive paths in
the fracture of FIG. 2B following fracture closure according to
some embodiments of the current application.
[0015] FIG. 3A is a schematic diagram of a fracture uniformly
filled with proppant and gel macrostructures according to some
embodiments of the current application.
[0016] FIG. 3B is a schematic diagram of the elongated
macrostructures following closure in the fracture of FIG. 3A
according to some embodiments of the current application.
[0017] FIG. 3C is a schematic diagram of the conductive paths in
the fracture of FIG. 3B following gel macrostructure breaking
according to some embodiments of the current application.
[0018] FIG. 4 is a schematic diagram of a spherical macrostructure
supporting settled proppant according to some embodiments of the
current application.
[0019] FIG. 5 is a schematic diagram of a transversely cylindrical
macrostructure supporting settled proppant according to some
embodiments of the current application.
[0020] FIG. 6 is a schematic diagram of a longitudinally
cylindrical macrostructure supporting settled proppant according to
some embodiments of the current application.
[0021] FIG. 7 is a schematic diagram of the cluster volume
corresponding to proppant supported on a cylindrical macrostructure
in a fracture according to some embodiments of the current
application.
[0022] FIG. 8A is a photograph of a slot filled with proppant and
gel macrostructures as described in Example 1 according to some
embodiments of the current application.
[0023] FIG. 8B is a photograph of the slot of FIG. 8A following
some proppant settlement as described in Example 1 according to
some embodiments of the current application.
[0024] FIG. 9A is a photograph of a slot filled with proppant and
gel macrostructures as described in Example 3 according to some
embodiments of the current application.
[0025] FIG. 9B is a photograph of the slot of FIG. 9A following
breaking of the gel macrostructures as described in Example 3
according to some embodiments of the current application.
[0026] FIG. 10A is a photograph of a slot filled with gel
macrostructures as described in Example 4 according to some
embodiments of the current application.
[0027] FIG. 10B is a photograph of the slot of FIG. 10A following
breaking of the gel macrostructures as described in Example 4
according to some embodiments of the current application.
[0028] FIG. 11A is a photograph of a slot filled with proppant and
fiber macrostructures as described in Example 5 according to some
embodiments of the current application.
[0029] FIG. 11B is a photograph of the slot of FIG. 11A following
some proppant settlement as described in Example 5 according to
some embodiments of the current application.
DETAILED DESCRIPTION OF SOME ILLUSTRATIVE EMBODIMENTS
[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] According to some embodiments herein, a method for treating
a subterranean formation penetrated by a wellbore may comprise
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 a fracture in the formation;
aggregating the solid particulate in the fracture to form clusters
at respective interfaces with adjacent macrostructures; and
reducing pressure in the fracture to prop the fracture open on the
clusters and form interconnected, hydraulically conductive channels
between the clusters.
[0035] According to some embodiments of the method, the solid
particulate comprises disaggregated proppant and the treatment
fluid stage is a proppant-laden hydraulic fracturing fluid.
According to some embodiments of the method, the carrier fluid
comprises fiber present in the fluid spaces around the
macrostructures to stabilize the treatment stage fluid for the
injection into the fracture.
[0036] According to some embodiments, the method may further
comprise viscosifying the carrier fluid for injection into the
formation, and breaking the carrier fluid (thus reducing its
viscosity) in the fracture to trigger the aggregation of the solid
particulates.
[0037] According to some embodiments, the method may further
comprise successively alternating concentration modes of the
macrostructures in the treatment stage fluid between a relatively
macrostructure-rich mode and a macrostructure-lean mode during the
treatment stage fluid injection.
[0038] According to some embodiments of the method, the
macrostructures comprise viscous gel. According to some embodiments
of the method, the macrostructures comprise viscous gel comprising
crosslinked polymer. According to some embodiments of the method,
the macrostructures comprise viscous gel comprising crosslinked
polymer selected from polysaccharides, polyacrylates, alginates,
polyacrylamides, and combinations thereof. According to some
embodiments of the method, the macrostructures comprise viscous gel
reinforced with proppant, subproppant, fiber or a combination
thereof.
[0039] According to some embodiments, the method may further
comprise degrading the macrostructures after the aggregation of the
solid particulate in the fracture.
[0040] According to some embodiments, the method may further
comprise elongating the macrostructures in the fracture. According
to some embodiments of the method, the macrostructures comprise a
gel relatively more viscous than the carrier fluid, and the method
may further comprise elongating the macrostructures in the fracture
by restraining flow of the macrostructures in the fracture relative
to the carrier fluid, by compression of the macrostructures during
fracture closure, or by a combination thereof.
[0041] According to some embodiments of the method, the
macrostructures comprise viscous gel and the method may further
comprise compression and elongation of the macrostructures during
fracture closure to form gel-filled channels comprising a plurality
of the elongated macrostructures in contact with each other.
[0042] According to some embodiments of the method, the
macrostructures in the injection comprise a volume in the treatment
fluid from 5 to 30 volume percent [e.g. 15 vol %] and the solid
particulate comprises a volume in the treatment fluid from 95 to 70
volume percent [e.g., 85 vol %], based on the total volume of the
macrostructures and solid particulate in the treatment fluid.
[0043] According to some embodiments of the method, the
macrostructures have a dimension at least 10 times larger than the
solid particulate. According to some embodiments of the method, the
macrostructures comprise long fibers having a length of at least
about 0.75 cm. According to some embodiments of the method, the
macrostructures comprise long fibers having a length of from about
1 cm to about 7.5 cm, or from 1 cm to 5 cm.
[0044] According to some embodiments of the method, the injection
into the fracture is at a continuous rate of the treatment fluid
stage with a continuous concentration of the solid particulate; and
further comprising, while maintaining the continuous rate and solid
particulate concentration during injection of the treatment fluid
stage, successively alternating concentration modes of the
macrostructures in the treatment fluid stage between a plurality of
relatively macrostructure-rich modes and a plurality of
macrostructure-lean modes. According to some embodiments, the
injection of the treatment fluid stage forms a homogenous region
within the fracture of continuously uniform distribution of the
first solid particulate, and wherein the alternation of the
concentration modes of the macrostructures forms heterogeneous
areas within the fracture comprising macrostructure-rich areas and
macrostructure-lean areas.
[0045] According to some embodiments, the method may further
comprise forming bridges with the macrostructures in the fracture
to retain the clusters.
[0046] According to some embodiments of the method, the
macrostructures are selected from a fiber, a floc, a flake, a
ribbon, a platelet, a rod, or a combination thereof.
[0047] According to some embodiments of the method, the
macrostructures are selected from the group consisting of
polylactic acid (PLA), polyglycolic acid (PGA), polyethylene
terephthalate (PET), polyester, polyamide, polycaprolactam and
polylactone, poly(butylene succinate), polydioxanonepolylactic
acid, polyester, polycaprolactam, polyamide, polyglycolic acid,
polyterephthalate, or a combination thereof.
[0048] According to some embodiments of the method, the
macrostructures are long fibers selected from the group consisting
of 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, cellulose, wool, basalt, glass, rubber, acrylic,
mica, and combinations thereof. According to some embodiments of
the method, the macrostructures comprise sticky fiber.
[0049] According to some embodiments of the method, the
macrostructures are degradable and the method may further comprise
degrading the macrostructures after closure of the fracture.
[0050] According to some embodiments, a system may comprise a
subterranean formation penetrated by a wellbore; a treatment slurry
stage disposed in the wellbore, the treatment slurry stage
comprising a slurry of a solid particulate freely dispersed in
fluid spaces around macrostructures suspended in a carrier fluid;
and a pump system to inject 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.
[0051] According to some embodiments of the system, the solid
particulate comprises disaggregated proppant and the treatment
fluid stage is a proppant-laden hydraulic fracturing fluid.
[0052] According to some embodiments of the system, the carrier
fluid comprises fiber present in the fluid spaces around the
macrostructures to stabilize the treatment stage fluid for the
injection into the fracture.
[0053] According to some embodiments of the system, the treatment
slurry stage further comprises a viscosifier in the carrier fluid
and a breaker to break the carrier fluid in the fracture to enable
the aggregation of the solid particulate.
[0054] According to some embodiments of the system, the treatment
slurry stage further comprises successively alternating
concentration modes of the macrostructures in the treatment slurry
stage between a relatively macrostructure-rich mode and a
macrostructure-lean mode during the treatment slurry stage
injection.
[0055] According to some embodiments of the system, the
macrostructures comprise viscous gel. According to some embodiments
of the system, the macrostructures comprise viscous gel comprising
crosslinked polymer. According to some embodiments of the system,
the macrostructures comprise viscous gel comprising crosslinked
polymer selected from polysaccharides, polyacrylates, alginates,
polyacrylamides, and combinations thereof. According to some
embodiments of the system, the macrostructures comprise viscous gel
reinforced with proppant, subproppant, fiber or a combination
thereof. According to some embodiments of the system, the
macrostructures comprise a gel relatively more viscous than the
carrier fluid.
[0056] According to some embodiments of the system, the
macrostructures comprise a volume in the treatment slurry stage
from 5 to 30 volume percent [e.g. 15 vol %] and the solid
particulate comprises a volume in the treatment slurry stage from
95 to 70 volume percent [e.g., 85 vol %], based on the total volume
of the macrostructures and solid particulate in the treatment
slurry stage.
[0057] According to some embodiments of the system, the
macrostructures have a dimension at least 10 times larger than the
solid particulate. According to some embodiments of the system, the
macrostructures comprise long fibers having a length of at least
about 0.75 cm. According to some embodiments of the system, the
macrostructures comprise long fibers having a length of from about
1 cm to about 7.5 cm.
[0058] With reference to FIGS. 1A-1C, in some embodiments of the
disclosure, treatment fluid is injected from supply station 10
through wellbore 12 and portal 14, e.g., perforation(s) in a cased
completion or fracture opening(s) in the case of an open hole
completion, into fracture 16 as indicated by flow arrow 18, to more
or less uniformly distribute solid particulate 20, e.g., proppant
and/or subproppant particles, and macrostructures 22, e.g., gel
bodies, fibers or the like. At shut in and/or activation of a
trigger, the particulate 20 settles as indicated by flow arrows 24
in FIG. 1A, and forms clusters 26 at macrostructures 22 as shown in
FIGS. 1B-1C, which keep the fracture open and form flow channels
around the clusters 26. As used herein, a macrostructure refers to
a physical body, which may be solid, semi-solid or gelatinous,
having a dimension sufficient to retain a plurality of proppant
particles on a surface thereof, i.e., at least 3 times larger than
the proppant or the largest ones of other solid particulates. In
some embodiments, the macrostructures may have at least one
dimension larger than 5 mm, e.g., from 5 mm to 80 mm, or from 8 mm
to 50 mm, or from 25 to 50 mm, or from 10 to 30 mm, etc.
[0059] In some embodiments, the macrostructures may comprise a
material, such as fibers, flocs, flakes, discs, rods, stars, balls,
blobs, etc., for example, which may be distributed in the fracture,
homogeneously and/or heterogeneously, and having a capability to
anchor to a surface of the fracture, e.g., by having a size to be
compressed between opposing fracture surfaces and/or a surface(s)
with an adhesive or attractant characteristic to adhere or cling to
a fracture surface. As used herein, the term "flocs" includes both
flocculated colloids and colloids capable of forming flocs in the
treatment fluid.
[0060] In some embodiments, the particulate solids may be proppant
or gravel. "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.
[0061] "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.
[0062] In some embodiments the macrostructures 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.
[0063] In some embodiments, the treatment fluid comprises a liquid
carrier fluid such as water, brine, oil or an emulsion, invert
emulsion or the like, or an energized fluid or foam. In some
embodiments, the liquid comprises a viscosified carrier fluid, and
the method may further comprise reducing the viscosity of the
carrier fluid in the fracture to induce settling of the solid
particulate prior to closure of the fracture, and thereafter
allowing the fracture to close.
[0064] 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.
[0065] 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.
[0066] "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.
[0067] "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.
[0068] 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.
[0069] The terms "energized fluid" and "foam" 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 term "energized fluid" also encompasses foams and
refers to any stable mixture of gas and liquid, regardless of the
foam quality. Energized fluids comprise any of: [0070] (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; [0071]
(b) Foams, consisting generally of a gas phase, an aqueous phase
and a solid phase. At high pressures the foam quality is typically
low (i.e., the non-saturated gas volume is low), but quality (and
volume) rises as the pressure falls. 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 [0072] (c) Liquefied gases.
[0073] 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.
[0074] 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.
[0075] 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.
[0076] 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.
[0077] 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.
[0078] 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 microstructure or other
particle(s) 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.
[0079] 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.
[0080] 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 US20130233542, each
of which are hereby incorporated herein by reference.
[0081] "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.
[0082] 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.
[0083] 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.
[0084] "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.
[0085] 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 "24h-static", "48h-static" or "72h
static". Dynamic settling test conditions generally indicate the
vibratory frequency and duration, e.g., 4h@15 Hz (4 hours at 15
Hz), 8h@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., 4h@15 Hz/20h-static refers to 4
hours vibration followed by 20 hours static, or 8h@15 Hz/10d-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 "8h@15 Hz/10d-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.
[0086] As used herein, a concentrated blend slurry (CBS) may meet
at least one of the following conditions: [0087] (1) the slurry has
a low-shear viscosity equal to or greater than 1 Pa-s (5.11
s.sup.-1, 25.degree. C.); [0088] (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 [0089] (3) the largest particle mode in the slurry has a
static settling rate less than 0.01 mm/hr; or [0090] (4) the depth
of any free fluid at the end of a 72-hour static settling test
condition or an 8h@15 Hz/10d-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 [0091] (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 8h@15
Hz/10d-static dynamic settling test condition is no more than
+/-20% of the initial dynamic viscosity; or [0092] (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 8h@15 Hz/10d-static dynamic settling test condition is no
more than 5% greater than the initial SVF; or [0093] (7) the
density across the column strata below any free water layer after
the 72-hour static settling test condition or the 8h@15
Hz/10d-static dynamic settling test condition is no more than 1% of
the initial density.
[0094] 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.
[0095] 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.
[0096] 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.
[0097] 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.
[0098] 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.
[0099] 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.
[0100] In some embodiments, where the macrostructures are made from
a gel ball material, the gel ball material may be presheared prior
to mixing with the base fluid, and/or the base fluid and material
suitable for forming the ball may be mixed together in an
appropriate mixer to provide the proper shear and other conditions
to obtain the gel bodies of the desired size and distribution, such
as, for one example, at a ratio of 70 to 95% by volume of proppant
or other solid particulate to 5 to 30% by volume of gel body
material, e.g., 85% to 15%, based on the total volume of gel body
material and solid particulate(s).
[0101] The treatment fluid in some embodiments may also contain a
breaker for the viscoelastic carrier fluid to lower the viscosity
after the fluid is placed in the fracture, prior to or after
fracture closure. The change in viscosity in these embodiments
allows the solid particles such as sand or other proppant to settle
on top of the gel bodies, where the gel bodies, due to their higher
viscosity and size, are anchored in the formation and capture the
solid particulate to create clusters. In these embodiments, the
clusters maintain the fracture open after closure stress is applied
while the space surrounding the clusters is left free of proppant
to create channels. Additional breaker may be employed in some
embodiments to fully break the carrier fluid and/or to break the
gel body material after fracture closure to create conductive
pathways.
[0102] This channelization phenomenon of some embodiments is
observed in FIGS. 2A-2C. In FIG. 2A, immediately following
injection of the treatment fluid(s), the generally vertically
oriented fracture 40 may contain a fairly even or homogenous
distribution of proppant particles 42 and gel bodies 44. In FIG.
2B, settlement of the proppant in the fracture 42, e.g., prior to
closure, has aggregated the proppant and resulted in the formation
of proppant clusters 46 on the upper surfaces of the immobilized
gel bodies 44. Then after closure as seen in FIG. 2C, conductive
paths 48 are formed between the clusters 46.
[0103] In other embodiments, after the fluid is pumped into the
fracture 50 to distribute the particulate slurry 52 and gel bodies
54 as seen in FIG. 3A, the closure stress is applied on the gel
bodies 54 which expand radially and may connect laterally to one or
more adjacent gel bodies 54 as seen in FIG. 3B, and the gel bodies
54 may then be broken to form a connected flow path 56 along the
profiles 58 of the respective gel bodies, as seen in FIG. 3C.
[0104] For example, the gel body breaker may contact the gel bodies
54 when the stress from the formation is applied, lowering the
viscosity of the gel bodies 54 and allowing them to flow, e.g.,
into the formation and/or toward the wellbore during flowback. In
some embodiments, e.g., where closure stress may not be sufficient
to break a frangibly encapsulated breaker, a thermally sensitive
encapsulant such as an encapsulated acid may additionally or
alternatively be used as a breaker, whereby the temperature trigger
releases the acid, lowers the pH and de-crosslinks the polymer in
the gel bodies. When the gel bodies 54 break, the resulting voided
spaces may create a network 56 of channels 58. In these
embodiments, the carrier fluid may or may not be broken before the
fracture closure, proppant may or may not settle and aggregate to
form clusters, and the carrier fluid may or may not be lost to the
formation through natural fractures, surface wetting or low fluid
loss control properties of the fluid.
[0105] In some embodiments, as mentioned, the gel bodies can also
be formulated to optionally contain fibers, proppant at relatively
high concentration, e.g., 0.6 g/mL (5 ppa) or more, or a
combination thereof, referred to herein as composite gel bodies.
These composite gel bodies in some embodiments are incorporated in
a viscous base fluid and pumped in a fracturing treatment. The base
fluid in some embodiments may optionally contain fiber, proppant or
a combination of both. After placement, the fluid used to carry
these gel bodies can be leaked off into the formation or flowed
back as the fracture is closing. The gel bodies, however, may be
retained in the fracture due to a large size relative to the
fracture width and/or high viscosity relative to the carrier fluid.
When the fracture closes in some embodiments, the gel bodies made
with proppant and/or fiber may act as or reinforce the proppant
clusters to facilitate holding the fracture open and improve
conductivity.
[0106] In some embodiments, changes in salinity concentrations
between the composite gel bodies and the formation brine may be
used to shrink the gel bodies to give higher solid concentration
and thus thicker pillars. These solid laden gel bodies in some
embodiments may be sufficiently strong and stiff to support and
prop the fracture open upon closure, i.e., the composite gel bodies
may function as proppant and/or as a proppant adjunct. In some
embodiments, channels may be formed surrounding the composite
bodies, with high conductivity for production.
[0107] According to some embodiments herein, the macrostructures
may form "shelves" on their upper surfaces, which may be
distributed along the fracture height and length. Where the
fracture(s) generally has a variable width depending on the
distance from the well and wall surface imperfections, the
macrostructures in some embodiments, may have a range of different
sizes to be effectively placed between the fracture walls in
different locations, e.g., larger macrostructures where the
fracture is wider and smaller macrostructures where the fracture is
narrower. The macrostructures in some embodiments may not have a
substantial compaction strength, and in some embodiments the
macrostructures may have a specific gravity comparable to the
carrier fluid or be nearly neutrally buoyant, e.g., 95 to 100% of
the specific gravity of the carrier fluid.
[0108] In some embodiments, the cumulative surface area of the
terraces, or the horizontal projection area, provided by the
macrostructures, determines the amount of proppant that can be
retained on them. On the other hand, too high macrostructure
concentrations in a slurry may lead to plugging of the perforations
or fractures during injection or attempted injection. While the
macrostructure shape is not limited herein and can be any
appropriate for the particular application, in some embodiments the
shape is elongated with high aspect ratio. For spherical
macrostructure 60 the ratio of horizontal projection area to volume
comprises 3/2d as seen in FIG. 4, where d is the diameter of the
sphere; for transverse disc macrostructure 70, 4/.pi.D as seen in
FIG. 5, where D is the diameter and d is the thickness; whereas the
horizontal elongated cylindrical macrostructure 80, with diameter d
and length l as seen in FIG. 6, has a projection area/volume ratio
expressed as 4/.pi.d.
[0109] The macrostructure particles 80 in some embodiments may be
oriented horizontally in the flow of the carrier fluid during
pumping, so they will naturally form shelves when stuck in the
fracture. Furthermore, while proppant covers substantially the
entire top surface of an elongated particle, significantly less
proppant is held by a spherical or disc-shaped particle, e.g., at
the margins where the slope of the macrostructure exceeds the angle
of repose. The proppant pillar volume also depends on the material
angle of repose, which for most of fracturing sands and proppants
in some embodiments is in the range of 27-35.degree.. It is
important to find an optimal additive concentration in the slurry.
It is possible to evaluate concentration based on volume balance
between additive material and proppant, as illustrated in the
examples below.
[0110] 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 in a fracture after it has
been filled with proppant particles, which in some embodiments, may
be injected at a generally continuous proppant particle
concentration. 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, such that the channel has a relatively higher
conductivity than adjacent non-channel areas.
[0111] 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.
[0112] Conversely, a parameter as a function of another variable
such as time, 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.
[0113] In embodiments, the conductive channels are formed in situ
after placement of the proppant particles in the fracture by
differential movement of the proppant particles, e.g., 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.
[0114] In some embodiments, a treatment slurry stage has a
continuous concentration of a first solid particulate, e.g.,
proppant, and a discontinuous concentration of the microstructures
that facilitates either clustering of the first solid particulate
in the fracture, or anchoring of the clusters in the fracture, or a
combination thereof, to form anchored clusters of the solid
particulate to prop open the fracture upon closure. As used herein,
an "anchorant" refers to a material, a precursor material, or a
mechanism, that inhibits settling, or preferably stops settling, of
particulates or clusters of particulates in a fracture, whereas an
"anchor" refers to an anchorant such as a microstructure that is
active or activated to inhibit or stop the settling.
[0115] In some embodiments, the microstructure 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 microstructures may adhere to each other to
facilitate consolidation, stability and/or strength of the formed
clusters.
[0116] In some embodiments, the microstructure 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 to form
the microstructures as in a two-reactant system, a
catalyst/reactant system, a pH-sensitive reactant/pH modifier
system, or the like.
[0117] In some embodiments, the microstructure may form lower
boundaries for particulate settling.
[0118] In some embodiments, a method for treating a subterranean
formation penetrated by a wellbore comprises: injecting a treatment
stage fluid above a fracturing pressure to form a fracture in the
formation; continuously distributing a first solid particulate into
the formation in the treatment stage fluid; aggregating the first
solid particulate distributed into the fracture to form
spaced-apart clusters in the fracture; anchoring at least some of
the clusters in the fracture to inhibit aggregation of at least
some of the clusters; reducing pressure in the fracture to prop the
fracture open on the clusters and form interconnected,
hydraulically conductive channels between the clusters.
[0119] In some embodiments, the first solid particulate
continuously distributed in the treatment stage fluid comprises
disaggregated proppant at a continuous concentration. In some
embodiments, the aggregation comprises triggering settling of the
distributed first solid particulate. In some embodiments, the
method further comprises viscosifying the treatment stage fluid for
distributing the first solid particulate into the formation, and
breaking the treatment stage fluid in the fracture to trigger the
settling. In some embodiments, the method further comprises
successively alternating concentration modes of a microstructure in
the treatment stage fluid between a relatively microstructure-rich
mode and an microstructure-lean mode during the continuous
distribution of the first solid particulate into the formation in
the treatment stage fluid to facilitate one or both of the cluster
aggregation and anchoring.
[0120] In some embodiments, the microstructure-lean concentration
mode is free or essentially free of microstructure, or a difference
between the concentrations of the microstructure-rich and
microstructure-lean modes is at least 10, or at least 25, or at
least 40, or at least 50, or at least 60, or at least 75, or at
least 80, or at least 90, or at least 95, or at least 98, or at
least 99, or at least 99.5 weight percent of the microstructure
concentration of the microstructure-rich mode. A
microstructure-lean mode is essentially free of microstructure if
the concentration of microstructure is less than 0.5 percent based
on the volume of the microstructure concentration of the
microstructure rich mode.
[0121] In some embodiments, the conductive channels extend in fluid
communication from adjacent a face of in 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.
[0122] In some embodiments, a method for treating a subterranean
formation penetrated by a wellbore comprises: injecting into a
fracture in the formation at a continuous rate a treatment fluid
stage with a continuous first solid particulate concentration;
while maintaining the continuous rate and first solid particle
concentration during injection of the treatment fluid stage,
successively alternating concentration modes of a microstructure in
the treatment fluid stage between a plurality of relatively
microstructure-rich modes and a plurality of microstructure-lean
modes within the injected treatment fluid stage.
[0123] In some embodiments, the injection of the treatment fluid
stage forms a homogenous region within the fracture of continuously
uniform distribution of the first solid particulate. In some
embodiments, the alternation of the concentration of the
microstructure forms heterogeneous areas within the fracture
comprising microstructure-rich areas and microstructure-lean
areas.
[0124] In some embodiments, the injected treatment fluid stage
comprises a viscosified carrier fluid, and the method may further
comprise reducing the viscosity of the carrier fluid in the
fracture to induce settling of the first solid particulate prior to
closure of the fracture, and thereafter allowing the fracture to
close.
[0125] In some embodiments, the method may also include forming
bridges or terraces with the microstructures in the fracture and
forming conductive channels between the bridges with the
microstructure-lean modes.
[0126] In some embodiments, a method for treating a subterranean
formation penetrated by a wellbore comprises: injecting into a
fracture in the formation at a continuous rate a treatment fluid
stage comprising a viscosified carrier fluid with a continuous
first solid particulate concentration and a continuous
microstructure concentration to form a homogenous region within the
fracture of continuously uniform distribution of the first solid
particulate and the microstructures; reducing the viscosity of the
carrier fluid within the homogenous region to induce settling of
the first solid particulate prior to closure onto the
microstructures to form pillars in corresponding to clusters of the
settled first solid particulate and channels corresponding to areas
from which the first solid particulate has settled; and thereafter
allowing the fracture to close onto the pillars.
[0127] In some embodiments, the microstructure may comprise a
degradable material. In some embodiments, the microstructure 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 microstructure may comprise acrylic fiber. In
some embodiments the microstructure may comprise mica.
[0128] In some embodiments, the microstructure is present in the
microstructure-laden stages of the treatment slurry 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 microstructure may be from 0.05 vol % less than 5 vol %,
or less than 1 vol %, or less than 0.5 vol %. The microstructure
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 %.
[0129] In further embodiments, the microstructure 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
microstructure 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 microstructure 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 microstructure 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 microstructure 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.
[0130] In further embodiments, the microstructure 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.
[0131] In further embodiments, the microstructure 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
microstructure 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
microstructure 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.
[0132] In some embodiments, the microstructure 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 EV A, 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.
[0133] In some embodiments, the ability of the fracturing fluid to
suspend the proppant is reduced after finishing the fracturing
treatment and before fracture closure to a level which triggers
gravitational settling of the propping agent inside the fracture.
For example, the fracturing fluid may be stabilized during
placement with a viscosified carrier fluid and destabilized by
breaking the viscosity after placement in the fracture and before
closure. Proppant settling results in the creation of heterogeneity
of proppant distribution inside the fracture because the rate of
proppant settling in presence of fiber is significantly slower than
without fiber. At some certain concentrations of fiber and propping
agent according to embodiments herein, it is possible to enable the
creation of stable interconnected proppant free areas and proppant
rich clusters which in turn enables high conductivity of the
fracture after its closure.
EXAMPLES
Example 1
[0134] demonstration of concentration evaluation based on volume
balance between cylindrical macrostructures and proppant. In the
case of the elongate cylinder shown in FIG. 7, the volume of the
cylinder shelf, Va, is given in Eq. 1:
V.sub.a=l.pi.d.sup.2/4 (1)
where l is the length and d is the diameter of the cylinder, which
is also just equal to the width of the fracture in this example.
The volume of the proppant heap on the top is given by Eq. 2:
V.sub.heap=dl.sup.2 tan .alpha./4 (2)
where .alpha. is the angle of repose of the proppant.
[0135] Considering porosity of proppant pack as .phi., the proppant
volume V.sub.p in the heap is given by Eq. 3:
V.sub.p=(1-.phi.)V.sub.heap=(1-.phi.)dl.sup.2 tan .alpha./4 (3)
[0136] If volumetric proppant concentration (fraction) in the
slurry is denoted as C.sub.p, then optimal volumetric concentration
of additive material C.sub.a can be defined according to the
formula given in Eq. 4:
C a = C p V a V p or C a = C p .pi. d .PHI. l tan .alpha. ( 4 )
##EQU00001##
[0137] This concentration ratio in this example is based on the
assumption that all macrostructures are covered with proppant and
all proppant is accumulated on the terraces. The cylindrical
macrostructures are also assumed for the purpose of this example to
be oriented horizontally in the flow and once the particle sticks
between the fracture walls its orientation does not change, as it
provides minimum resistance to flow.
[0138] Eq. (4) establishes the ratio between required volume
concentration of additive and volume concentration of proppant. For
certain proppant material volume and mass of additive can be
calculated. In this example, the proppant is sand with a density of
2.65 g/cm.sup.3, pack porosity 0.35, and angle of repose
30.degree.; the macrostructures are cylinders with length of 25 mm,
diameter 5 mm and have density equal to 1.2 g/cm.sup.3. Then volume
and mass ratios will then be as follows in Eqs. 5-7:
C a = C p .pi. d ( 1 - .PHI. ) l tan .alpha. = C p 3.14 0.5 ( 1 -
0.35 ) 2.5 0.58 = 0.7 C p ( 5 ) 0.7 = C a C p = V a V p = M a .rho.
a M p .rho. p ( 6 ) M a = 0.7 .rho. a .rho. p M p = 0.7 1.2 2.65 M
p = 0.32 M p ( 7 ) ##EQU00002##
where M.sub.a is the macrostructures mass, M.sub.p is the proppant
mass, .rho..sub.a is density of the macrostructures material,
.rho..sub.p is density of the proppant material. Eq. 7 provides the
mass ratio. In other words, for every 1000 kg of sand/proppant, 320
kg of macrostructures are required. Note that the mass of
sand/proppant required to achieve the same fracture conductivity in
case of heterogeneous proppant placement can be 30-50% less than in
case of conventional proppant placement.
[0139] The ratio of Eq. 7 strongly depends on the shape of additive
particles. For the same diameter additive particles, but with 50 mm
length, the ratio between volume concentrations (Eq. 8) will be
different as well as the mass ratio (Eq. 9):
C a = C p .pi. d ( 1 - .PHI. ) l tan .alpha. = C p 3.14 0.5 ( 1 -
0.35 ) 5 0.58 = 0.35 C p ( 8 ) M a = 0.35 .rho. a .rho. p M p =
0.35 1.2 2.65 M p = 0.16 M p ( 9 ) ##EQU00003##
Thus the required number of 50 mm macrostructures is four time less
than the required number of 25 mm ones. Obviously, the mass of the
cylinder depends on its length linearly and the mass of the
proppant heap on the top is proportional to the squared cylinder
length and density. Particles are not required to be high stress
and crush resistant.
Example 2
[0140] This example is based on a laboratory experiment using
fragments of soda straw to represent tubular macrostructures,
having a length of 20 mm, diameter 5 mm, thickness of the wall 0.1
mm, density 0.95 g/cm.sup.3. Sand 70/140 US mesh (density 2.65
g/cm.sup.3, porosity of pack 0.35) and mica 70/140 US (density 2.8
g/cm.sup.3, porosity of pack 0.15) were used as proppant.
[0141] The tubes were placed horizontally between the walls of a
settling PLEXIGLAS polycarbonate slot. The slot was then filled
with water. Proppant was poured from the top of the slot. The heaps
formed on the tubes were measured. In case of sand which had an
angle of repose close to 30.degree., the volume heap is calculated
in Eq. 10:
V heap = d l 2 tan .alpha. 4 = 5 20 20 0.58 4 = 290 mm 3 ( 10 )
##EQU00004##
[0142] Taking into account porosity of the proppant pack, the
volume of proppant in the heap is calculated in Eq. 11:
V.sub.p=(1-.phi.)V.sub.heap=(1-0.65)290=101.5 mm.sup.3 (11)
[0143] The volume of the tube (just walls without void space) is
calculated in Eq. 12:
V a = l .pi. ( d 2 - ( d - .DELTA. d ) 2 ) 4 = 20 3.14 25 - 24 4 =
15.7 mm 3 ( 12 ) ##EQU00005##
[0144] Taking into account densities of materials the following
mass ratios occur in Eqs. 13 and 14:
M a = 0.35 .rho. a .rho. p M p = 0.35 1.2 2.65 M p = 0.16 M p ( 13
) M a = V a V p .rho. a .rho. p M p = 15.7 101.5 0.95 2.65 M p =
0.055 M p ( 14 ) ##EQU00006##
[0145] This means that if the macrostructures have a shape of
tubes, for each 1000 kg of proppant only 55 kg of macrostructures
are required. This value is significantly smaller compared to
ratios of Eqs. 7 and 9.
[0146] For the mica proppant an important observation was made.
Since mica particles are plate-like, the heap length is greater
than the length of shelve on which the heap lies. Some mica
particles stick out of the platform for a distance .DELTA.l, they
are hold by adjacent particles. The .DELTA.l value was measured to
be about 1 mm. Volume of the proppant heap is proportional to the
square of the base. Angle of repose for mica is about 40.degree..
In this case the volume of proppant in the heap is
V heap = d ( l + 2 .DELTA. l ) 2 tan .alpha. 4 = 5 22 22 0.84 4 =
508.2 mm 3 ( 15 ) ##EQU00007##
[0147] A heap of mica is significantly bigger than a heap of sand
(cf. Eq. 10) in the same conditions, although total mass of
proppant in this heap is less because of increased porosity of mica
package:
M.sub.sand=(1-.phi.)V.sub.heap.rho..sub.sand=(1-0.65)0.2902.65=0.27
g (16)
M.sub.mica=(1-.phi.)V.sub.heap.rho..sub.mica=(1-0.85)0.5082.8=0.21
g (17)
Example 3
[0148] In stimulation of a shale reservoir the estimated fracture
width during pumping in this example is assumed to be 5 mm near
wellbore and is considered to decrease linearly with distance down
to 0 mm at 500 m. The width is further assumed to be the same along
the whole fracture height. Proppant is supposed to be delivered 200
m from the wellbore. Therefore, if macrostructures have cylindrical
shape their diameters should be uniformly distributed from 3 mm to
5 mm to cover the area where proppant is going to be placed.
Example 4
[0149] In the following examples, gel ball materials were prepared
by hydrating the guar for 10-20 minutes in a 1000 mL Waring
blender, adding any fiber or solids to the mixture, and then
crosslinking the gel. A 100 g portion of the crosslinked gel was
transferred to a 500 mL blender cup and the speed was increased to
medium for 1 second, then speed immediately reduced to zero; this
was repeated three times for each 100 g of crosslinked gel, and the
resulting balls added to the carrier fluid. Most of the gel balls
were between 10-13 mm in diameter. The size of the balls is
dependent on the shear rate, which could be adjusted in the field
to obtain the desired size. In this example the macrostructures
were gel balls made with guar at a concentration of 12 g/L (100
ppt) and cross-linked with a borate crosslinker. The gel ball
material was then mixed in a carrier fluid consisting of a
viscoelastic fluid (ClearFRAC XT) containing 20 mL/L (20 gpt) of a
35-40 wt % surfactant solution and 3.3 mL/L (3.3 gpt) of a rheology
modifier solution, and also containing PLA fibers at 4.8 g/L (40
ppt) and 0.6 g/mL (5 ppa) of 20/40 mesh sand. The base fluid and
gel ball material were mixed at a ratio of 85% by volume of sand to
15% by volume of gel ball material. With reference to FIG. 8A, the
mixture was injected into a 152 mm (6-in.) by 203 mm (8 in.) slot
200 with a 3 mm wide gap and a transparent to obtain a more or less
random placement of gel balls 202 and distributed proppant 204.
Slots used to simulate reservoir fractures in this example had a
transparent front plate and sandpaper with a roughness of 100 mesh
grit was glued to the back wall of the slot. After 2 hours settling
time, as seen in FIG. 8B, the gel balls 202 supported settled
proppant 206, creating channels 208 formed under the gel balls
202.
Example 5
[0150] Example 4 was repeated with different carrier fluid and gel
ball compositions. In this example the gel ball material was made
with crosslinked sodium polyacrylate. The gel ball material was
then mixed in a carrier fluid comprising a viscoelastic fluid
containing guar at 3 g/L (25 ppt), 0.6 g/mL (5 ppa) of 20/40 mesh
sand, and 4.8 g/L (40 ppt) of crimped fibers measuring 12.7 mm (0.5
in.) in length and 40 um in diameter. The base fluid and gel ball
material were mixed at a ratio of 85% by volume of sand to 15% by
volume of gel ball material. The mixture was crosslinked with 2
mL/L (2 gpt) borate crosslinker solution, and DBE-5 ester at 70
ml/L (70 gpt), which hydrolyzes at elevated temperatures to form
acid, was used to de-crosslink the fluid to linear gel viscosity
after placement in a 152 mm (6-in.) by 203 mm (8 in.) slot 200 with
a 6 mm wide gap. The gel balls anchored on the rough (non-window)
surface of the cell and captured the settling proppant to create
clusters. Channels free of proppant were formed surrounding the
clusters. The remaining linear gel viscosity was then broken
completely with a chemical oxidant breaker to allow for flowback
through the formed channels.
Example 6
[0151] This example demonstrates the feasibility of radially
expanding gel ball macrostructures at fracture closure to contact
adjacent gel balls, and, upon breaking the contacting gel balls,
e.g., by releasing encapsulated and/or temperature activated
breaker present in the gel balls, creating flow paths through the
gel ball profiles. The carrier was a viscoelastic ClearFRAC XT
fluid, made with 20 mL/L (20 gpt) of a 35-40 wt % surfactant
solution and 3.3 mL/L (3.3 gpt) of a rheology modifier solution,
and also containing PLA fibers at 4.8 g/L (40 ppt) and 2.16 g/mL
(18 ppa) of a mixture of 70/140 mesh and 40/70 mesh sand. Gel
balls, made from guar at a concentration of 12 g/L (100 ppt) and
cross-linked with a borate crosslinker solution at 2 mL/L (2 gpt),
and also containing 4.8 g/L (40 ppt) PLA fibers, were added to the
fluid. The base fluid and gel ball material were mixed at a ratio
of 60% by volume of sand to 40% by volume of gel ball material. The
slurry was packed into a 152 mm (6-in.) by 203 mm (8 in.) slot 210
with a 3 mm wide gap to obtain a more or less random placement of
gel balls 212 and distributed proppant 214 as seen in FIG. 9A.
After 2 hours settling time at room temperature, as seen in FIG.
9B, the gel balls 212 maintained their integrity and position.
Example 7
[0152] In this example, the gel balls were formulated with a
combination of fibers and sand at relatively high concentration.
The gel balls contained 12 g/L (100 ppt) guar, 2 mL/L (2 gpt)
borate crosslinker solution, 4.8 g/L (40 ppt) PLA fibers and 0.36
g/mL (3 ppa) 20/40 mesh sand. The carrier fluid was comprised of
only ClearFRAC XT 20, made with 20 mL/L (20 gpt) of a 35-40 wt %
surfactant solution and 3.3 mL/L (3.3 gpt) of a rheology modifier
solution. The base fluid and gel ball material were mixed at a
ratio of 85% by volume of sand to 15% by volume of gel ball
material. The slurry was injected into a 152 mm (6-in.) by 203 mm
(8 in.) slot 220. FIGS. 10A and 10B show the slot immediately after
filling and after 2 hours at room temperature. After 2 hours, the
gel balls 222 maintained their integrity and position in the cell
while channels formed below and above the gel balls.
Example 8
[0153] In this example, long fibers were employed as the
macrostructures. The fibers were PLA fibers measuring 2.5-5.1 cm
(1-2 in.). The carrier fluid was a viscoelastic fluid (ClearFRAC
XT) containing 15 mL/L (15 gpt) of a 35-40 wt % surfactant solution
and 2.5 mL/L (2.5 gpt) of rheology modifier (such as borate
crosslinker) solution, and also containing short (5.6-7.1 mm long)
PLA fibers at 4.8 g/L (40 ppt) and 0.6 g/mL (5 ppa) of 20/40 mesh
sand. The long fibers were added to the carrier fluid at a low
concentration of 0.05 g/L. FIGS. 11 A and B were used to illustrate
the expected behavior of this mixture when placed into the
fracture. With reference to FIG. 11A, the mixture was injected into
a 965.2 mm (38 in.) by 2209.8 mm (87 in.) slot 230 with a 4 mm wide
gap to obtain a more or less uniform placement of the mixture.
Above the long streaks of proppant free areas 232, there is a tiny
(.about.1 mm) step 234 of the fracture surface. It can be seen that
this small disturbance gives rise to a clear hindering line for the
proppant clusters 236 to settle onto. Without wishing to be bound
by any theory, it is believed that the long fiber in the system may
create the same phenomenon.
[0154] 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.
* * * * *