U.S. patent application number 14/841143 was filed with the patent office on 2015-12-24 for delayed water-swelling materials and method of use.
The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Marina Nikolaevna Bulova, Simon Gareth James, Kseniya Nosova, Sergey Sokolov, Dean M. Willberg.
Application Number | 20150368549 14/841143 |
Document ID | / |
Family ID | 39092565 |
Filed Date | 2015-12-24 |
United States Patent
Application |
20150368549 |
Kind Code |
A1 |
Willberg; Dean M. ; et
al. |
December 24, 2015 |
DELAYED WATER-SWELLING MATERIALS AND METHOD OF USE
Abstract
A water absorbing composition includes a particle having a core
of a water-swelling material. A coating substantially surrounds the
core that temporarily prevents contact of water with the
water-swelling material. The coating may be formed from a layer of
water degradable material or a non-water-degradable, non-water
absorbent encapsulating layer. A quantity of particles including
delayed water-swelling particles formed at least in part from a
water-swelling material and, optionally, non-water-swelling
particles of the same or different size distributions can be used
in treating a formation penetrated by a wellbore. A slurry of the
particles is formed with a carrier fluid. The slurry of particles
is introduced into the wellbore of the formation to facilitate
treatment.
Inventors: |
Willberg; Dean M.; (Salt
Lake City, UT) ; Nosova; Kseniya; (Berdsk, RU)
; Bulova; Marina Nikolaevna; (Moscow, RU) ; James;
Simon Gareth; (Clamart, FR) ; Sokolov; Sergey;
(Novosibiirsk, RU) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Family ID: |
39092565 |
Appl. No.: |
14/841143 |
Filed: |
August 31, 2015 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
11557756 |
Nov 8, 2006 |
9120963 |
|
|
14841143 |
|
|
|
|
Current U.S.
Class: |
507/219 |
Current CPC
Class: |
C09K 8/68 20130101; C09K
2208/18 20130101; C09K 8/805 20130101; C09K 8/035 20130101; C09K
8/516 20130101; E21B 33/138 20130101 |
International
Class: |
C09K 8/80 20060101
C09K008/80 |
Claims
1. A water absorbing composition comprising a particle having a
core of a water-swelling material and a coating substantially
surrounding the core that temporarily prevents contact of water
with the water-swelling material, the coating being formed from at
least one of (1) a layer or layers of water degradable material and
(2) a non-water-degradable, non-water absorbent layer or layers of
encapsulating material.
2. The composition of claim 1, wherein: the water-swelling material
comprises at least one of a clay and a superabsorbing material.
3. The composition of claim 2, wherein: the clay is selected from
the group consisting of bentonite, montmorillonite, smectite,
nontronite, beidellite, perlite and vermiculite clays and
combinations of these; and the superabsorbing material is selected
from the group consisting of polymers and copolymers of acrylate,
acrylic acid, amide, acrylamide, saccharides, vinyl alcohol,
urethane, and combinations of these materials.
4. The composition of claim 1, wherein: the water degradable
material comprises a solid polymer acid precursor.
5. The composition of claim 1, wherein: the water degradable
material comprises a polylactic acid coating.
6. The composition of claim 1, wherein: the core further contains a
weighting material.
7. The composition of claim 6, wherein: the weighting material is
selected from the group consisting of silicates, aluminosilicates,
barite, hematite, ilmenite, manganese tetraoxide, manganosite,
iron, lead, aluminum and combinations of these.
8. The composition of claim 1, wherein: the core comprises an inner
core of proppant material with an outer layer of the water
absorbent material formed around the proppant material.
9. The composition of claim 1, wherein: the water-swelling material
comprises a superabsorbent material that has been surface
cross-linked to delay swelling further.
10. The composition of claim 1, wherein: the water-swelling
material is capable of absorbing at least the water-swelling
material's weight of water.
11. A method of treating a formation penetrated by a wellbore
comprising: providing a quantity of particles comprising delayed
water-swelling particles formed at least in part from a
water-swelling material and non-water-swelling particles of
different size distributions; forming a slurry of the particles
with a carrier fluid; and introducing the slurry of particles into
the wellbore of the formation.
12. The method of claim 11, wherein: the non-water-swelling
particles have a particle size of from about 0.035 mm to about 2.35
mm.
13. The method of claim 11, wherein: non-water-swelling particles
of at least two different size distributions are used wherein the
mean particle size of the larger non-water-swelling particles is at
least 1.5 times greater than that of the smaller non-water-swelling
particles.
14. The method of claim 11, wherein: the non-water-swelling
particles comprise coarse particles having a particle size of from
about 0.2 mm to about 2.35 mm and at least one of fine particles
having a particle size of less than about 0.1 mm and medium
particles having a particle size of from about 0.1 mm to less than
about 0.2 mm.
15. (canceled)
16. The method of claim 11, wherein: the particles have a specific
gravity that is at least one of the same, greater or less than the
specific gravity of the carrier fluid.
17. The method of claim 11, wherein: the water-swelling material
comprises at least one of a clay and a superabsorbing material.
18. The method of claim 17, wherein: the clay is selected from the
group consisting of bentonite, montmorillonite, smectite,
nontronite, beidellite, perlite and vermiculite clays and
combinations of these; and the superabsorbing material is selected
from the group consisting of polymers and copolymers of acrylate,
acrylic acid, amide, acrylamide, saccharides, vinyl alcohol,
urethane, and combinations of these materials.
19.-21. (canceled)
22. The method of claim 11, wherein: the delayed water-swelling
particles contain a weighting material.
23. The method of claim 22, wherein: the weighting material is
selected from the group consisting of silicates, aluminosilicates,
barite, hematite, ilmenite, manganese tetraoxide, manganosite,
iron, lead, aluminum and combinations of these.
24. The method of claim 11, wherein: the delayed water-swelling
particles are formed from particles having an inner core of
proppant material with a layer of the delayed water absorbent
material formed around the proppant material.
25.-26. (canceled)
27. The method of claim 11, wherein: the slurry is introduced into
the wellbore during or subsequent to introduction of a PAD fluid of
a fracturing treatment; and wherein the carrier fluid of the slurry
has a specific gravity that is at least one of greater or less than
the specific gravity of the PAD fluid.
28. The method of claim 27, wherein: the slurry contains materials
that provide buoyancy of the slurry within the PAD fluid.
29. The method of claim 28, wherein: the buoyancy providing
materials comprise at least one of polymer particles, hollow beads,
ceramic materials, porous particles, fibers and foaming agents.
30. The method of claim 27, wherein: the carrier fluid comprises
the PAD fluid.
31. The method of claim 27, wherein: the carrier fluid is
immiscible with the PAD fluid.
32. The method of claim 27, wherein: the carrier fluid is miscible
with the PAD fluid.
33. The method of claim 11, wherein: the carrier fluid comprises at
least one of a drilling mud or a completion brine.
34. A method of treating a formation penetrated by a wellbore
comprising: providing a quantity of particles comprising delayed
water-swelling particles formed at least in part from a
water-swelling material; forming a slurry of the particles with a
carrier fluid; and introducing the slurry into the wellbore during
or subsequent to introduction of a PAD fluid of a fracturing
treatment, wherein the carrier fluid of the slurry has a specific
gravity that is at least one of greater or less than the specific
gravity of the PAD fluid.
35. The method of claim 34, wherein: the slurry contains materials
that provide buoyancy of the slurry within the PAD fluid.
36. The method of claim 35, wherein: the buoyancy providing
materials comprise at least one of polymer particles, hollow beads,
ceramic materials, porous particles, fibers and foaming agents.
37. The method of claim 34, wherein: the carrier fluid comprises
the PAD fluid.
38. The method of claim 34, wherein: the particles comprise
non-water-swelling particles.
39. The method of claim 38, wherein: non-water-swelling particles
of at least two different size distributions are used wherein the
mean particle size of the larger non-water-swelling particles is at
least 1.5 times greater than that of the smaller non-water-swelling
particles.
40. The method of claim 38, wherein: the non-water-swelling
particles comprise coarse particles having a particle size of from
about 0.2 mm to about 2.35 mm and at least one of fine particles
having a particle size of less than about 0.1 mm and medium
particles having a particle size of from about 0.1 mm to less than
about 0.2 mm.
41. The method of claim 34, wherein: the water-swelling material
comprises at least one of a clay and a superabsorbing material.
42. The method of claim 41, wherein: the clay is selected from the
group consisting of bentonite, montmorillonite, smectite,
nontronite, beidellite, perlite and vermiculite clays and
combinations of these; and the superabsorbing material is selected
from the group consisting of polymers and copolymers of acrylate,
acrylic acid, amide, acrylamide, saccharides, vinyl alcohol,
urethane, and combinations of these materials.
43.-45. (canceled)
46. The method of claim 34, wherein: the delayed water-swelling
particles contain a weighting material.
47. The method of claim 46, wherein: the weighting material is
selected from the group consisting of silicates, aluminosilicates,
barite, hematite, ilmenite, manganese tetraoxide, manganosite,
iron, lead, aluminum and combinations of these.
48. The method of claim 34, wherein: the delayed water-swelling
particles are formed from particles having an inner core of
proppant material with a layer of the delayed water absorbent
material formed around the proppant material.
49.-50. (canceled)
51. The method of claim 34, wherein: the carrier fluid is
immiscible with the PAD fluid.
52. The method of claim 34, wherein: the carrier fluid is miscible
with the PAD fluid.
53. A method of treating a formation penetrated by a wellbore
comprising: providing a quantity of delayed water-swelling
particles having a core of a water-swelling material and wherein
the core has a coating substantially surrounding the core that
temporarily prevents contact of water with the water-swelling
material, the coating being formed from at least one of (1) a layer
or layers of water degradable material and (2) a layer or layers of
non-water-degradable, non-water absorbent encapsulating material;
forming a slurry of the particles with a carrier fluid; and
introducing the slurry of particles into the wellbore of the
formation.
54. The method of claim 53, wherein: non-water-swelling particles
are provided with the delayed water-swelling particles.
55. The method of claim 53, wherein: the slurry of particles is
positioned within a fracture of the formation.
56. The method of claim 53, wherein: the water-swelling material is
capable of absorbing at least the water-swelling material's weight
of water.
57. The method of claim 54, wherein: the non-water-swelling
particles have a particle size of from about 0.035 mm to about 2.35
mm.
58. The method of claim 54, wherein: non-water-swelling particles
of at least two different size distributions are used wherein the
mean particle size of the larger non-water-swelling particles is at
least 1.5 times greater than that of the smaller non-water-swelling
particles.
59. The method of claim 54, wherein: the non-water-swelling
particles comprise coarse particles having a particle size of from
about 0.2 mm to about 2.35 mm and at least one of fine particles
having a particle size of less than about 0.1 mm and medium
particles having a particle size of from about 0.1 mm to less than
about 0.2 mm.
60. (canceled)
61. The method of claim 53, wherein: the particles have a specific
gravity that is at least one of greater or less than the specific
gravity of the carrier fluid.
62. The method of claim 53, wherein: the water-swelling material
comprises at least one of a clay and a superabsorbing material.
63. The method of claim 62, wherein: the clay is selected from the
group consisting of bentonite, montmorillonite, smectite,
nontronite, beidellite, perlite and vermiculite clays and
combinations of these; and the superabsorbing material is selected
from the group consisting of polymers and copolymers of acrylate,
acrylic acid, amide, acrylamide, saccharides, vinyl alcohol,
urethane, and combinations of these materials.
64.-66. (canceled)
67. The method of claim 53, wherein: the delayed water-swelling
particles contain a weighting material.
68. The method of claim 67, wherein: the weighting material is
selected from the group consisting of silicates, aluminosilicates,
barite, hematite, ilmenite, manganese tetraoxide, manganosite,
iron, lead, aluminum and combinations of these.
69. The method of claim 53, wherein: the delayed water-swelling
particles are formed from particles having an inner core of
proppant material with a layer of the delayed water absorbent
material formed around the proppant material.
70.-77. (canceled)
78. The method of claim 53, wherein: the carrier fluid comprises at
least one of a drilling mud or a completion brine.
79. A method of treating a subterranean formation immediately
surrounding a wellbore penetrating the formation to reduce lost
fluid circulation during drilling operations comprising: providing
a quantity of particles comprising delayed water-swelling particles
formed at least in part from a water-swelling material; forming a
slurry of the particles with a carrier fluid; and introducing the
slurry into the wellbore at a pressure sufficient to fracture a
portion of the formation.
80. The method of claim 79, wherein: the carrier fluid comprises at
least one of a drilling mud or a completion brine.
81. The method of claim 79, wherein: the delayed water-swelling
particles comprise superabsorbing particles in a carrier fluid of
one of a non-aqueous fluid, an emulsion and an aqueous metal salt
solution that delays absorption of water.
82. The method of claim 79, wherein: the particles also comprise
non-water-swelling particles.
83. The method of claim 82, wherein: non-water-swelling particles
of at least two different size distributions are used wherein the
mean particle size of the larger non-water-swelling particles is at
least 1.5 times greater than that of the smaller non-water-swelling
particles.
84. The method of claim 82, wherein: the non-water-swelling
particles comprise coarse particles having a particle size of from
about 0.2 mm to about 2.35 mm and at least one of fine particles
having a particle size of less than about 0.1 mm and medium
particles having a particle size of from about 0.1 mm to less than
about 0.2 mm.
85. The method of claim 79, wherein: the water-swelling material
comprises at least one of a clay and a superabsorbing material.
86. The method of claim 85, wherein: the clay is selected from the
group consisting of bentonite, montmorillonite, smectite,
nontronite, beidellite, perlite and vermiculite clays and
combinations of these; and the superabsorbing material is selected
from the group consisting of polymers and copolymers of acrylate,
acrylic acid, amide, acrylamide, saccharides, vinyl alcohol,
urethane, and combinations of these materials.
87.-89. (canceled)
90. The method of claim 79, wherein: the delayed water-swelling
particles are formed from particles having an inner core of
proppant material with a layer of the delayed water absorbent
material formed around the proppant material.
91. (canceled)
92. The method of claim 79, further comprising: circulating a
drilling fluid within the wellbore during drilling after
introduction of the slurry.
93. The method of claim 79, further comprising: introducing a
cement into the wellbore after introduction of the slurry.
94. The method of claim 79, further comprising: introducing a
further well treatment fluid into the wellbore after introduction
of the slurry.
95. A method of positioning materials in a formation penetrated by
a wellbore comprising: providing a quantity of particles; forming a
slurry of the particles with a carrier fluid; introducing the
slurry of particles into the wellbore of the formation; and
introducing a second fluid into the wellbore of the formation prior
to or subsequent to the slurry, wherein the carrier fluid of the
slurry has a specific gravity that is at least one of greater or
less than the specific gravity of the second fluid.
96. The method of claim 95, wherein: the slurry contains materials
that provide buoyancy of the slurry within the second fluid.
97. The method of claim 96, wherein: the buoyancy providing
materials comprise at least one of polymer particles, hollow beads,
ceramic materials, porous particles, fibers and foaming agents.
98. The method of claim 95, wherein: the carrier fluid is
immiscible with the second fluid.
99. The method of claim 95, wherein: the carrier fluid is miscible
with the second fluid.
Description
BACKGROUND
[0001] In subterranean formations of oil and gas wells, the
formation may have insufficient stress barriers to contain
hydraulic fractures made within the producing zone. This can lead
to inefficient fracturing, with much of the treatment potentially
stimulating bare rock. Vertical fracture growth out of the
hydrocarbon bearing portions of the formation, either up or down,
may result from hydraulic fracturing in such formations having
little or no stress contrast between the formation layers. A
particular problem encountered in formations where there are
insufficient stress barriers is the fracturing or stimulation of
water or undesirable gas producing zones.
[0002] Containment of these undesirable fractures has been
accomplished in the past by placing an artificial barrier along the
boundaries of the fracture to prevent further fracture growth out
of the producing zone. Known methods for containing fracture growth
include placing of proppants and fluids with different densities in
the fracture to limit the undesirable fracture growth. The main
drawback to such techniques is the difficulty of providing proper
barrier placement such that the prior art methods are
unreliable.
[0003] In drilling operations, undesirable fractures may form in
areas adjacent to the well bore resulting in the lost circulation
of drilling fluid. Eventually, in highly permeable formations,
fluid is lost from the drilling fluid within the fracture so that
the mud consequently becomes dehydrated and blocks the fracture so
that there is no transmission of pressure to the tip of the
fracture and further fracture propagation is prevented. In shale or
low permeability formations, however, where there is little or no
fluid loss to the formation, the fracture tends to keep
propagating, particularly when using high pressure or high density
drilling fluids.
[0004] There is therefore a need to provide improvements in
compositions and methods used for containing such fractures.
SUMMARY
[0005] One embodiment of the invention is a water absorbing
composition containing a particle having a core of a water-swelling
material and a coating substantially surrounding the core that
temporarily prevents contact of water with the water-swelling
material; the coating is formed from at least one of (1) a layer or
layers of water degradable material and (2) a non-water-degradable,
non-water absorbent layer or layers of encapsulating material. In
various versions of this embodiment: the water-swelling material is
at least one of a clay and a superabsorbing material; the clay is
selected from bentonite, montmorillonite, smectite, nontronite,
beidellite, perlite and vermiculite clays and combinations of
these, and the superabsorbing material is selected from polymers
and copolymers of acrylate, acrylic acid, amide, acrylamide,
saccharides, vinyl alcohol, urethane, and combinations of these
materials; the water degradable material is a solid polymer acid
precursor, for example a polylactic acid coating; the core further
contains a weighting material, for example selected from silicates,
aluminosilicates, barite, hematite, ilmenite, manganese tetraoxide,
manganosite, iron, lead, aluminum and combinations of these; the
core includes an inner core of proppant material with an outer
layer of the water absorbent material formed around the proppant
material; the water-swelling material is a superabsorbent material
that has been surface cross-linked to delay swelling further; and
the water-swelling material is capable of absorbing at least the
water-swelling material's weight of water.
[0006] Another embodiment of the invention is a method of treating
a formation penetrated by a wellbore including the steps of:
providing a quantity of particles containing delayed water-swelling
particles formed at least in part from a water-swelling material
and non-water-swelling particles of different size distributions;
forming a slurry of the particles with a carrier fluid; and
introducing the slurry of particles into the wellbore of the
formation. In various aspects of this embodiment: the
non-water-swelling particles have a particle size of from about
0.035 mm to about 2.35 mm; non-water-swelling particles of at least
two different size distributions are used in which the mean
particle size of the larger non-water-swelling particles is at
least 1.5 times greater than that of the smaller non-water-swelling
particles; the non-water-swelling particles include coarse
particles having a particle size of from about 0.2 mm to about 2.35
mm and at least one of fine particles having a particle size of
less than about 0.1 mm and medium particles having a particle size
of from about 0.1 mm to less than about 0.2 mm; the water-swelling
material is a superabsorbent material that has been surface
cross-linked to delay swelling; the particles have a specific
gravity that is at least one of the same, greater or less than the
specific gravity of the carrier fluid; the water-swelling material
is at least one of a clay and a superabsorbing material; the clay
is selected from bentonite, montmorillonite, smectite, nontronite,
beidellite, perlite and vermiculite clays and combinations of
these, and the superabsorbing material is selected from polymers
and copolymers of acrylate, acrylic acid, amide, acrylamide,
saccharides, vinyl alcohol, urethane, and combinations of these
materials; the delayed water-swelling particles are formed from
particles having a core of water-swelling material with a coating
of water degradable material; the water degradable material is a
solid polymer acid precursor, for example polylactic acid; the
delayed water-swelling particles contain a weighting material, for
example selected from silicates, aluminosilicates, barite,
hematite, ilmenite, manganese tetraoxide, manganosite, iron, lead,
aluminum and combinations of these; the delayed water-swelling
particles are formed from particles having an inner core of
proppant material with a layer of the delayed water absorbent
material formed around the proppant material; the delayed
water-swelling particles are formed from superabsorbing polymer
particles that are crosslinked at the surface to reduce penetration
by water; the superabsorbing polymer particles are further coated
with at least one of (1) a layer or layers of water degradable
material and (2) a layer or layers of non-water-degradable,
non-water absorbing encapsulating material; the slurry is
introduced into the wellbore during or subsequent to introduction
of a PAD fluid of a fracturing treatment; the carrier fluid of the
slurry has a specific gravity that is at least one of greater or
less than the specific gravity of the PAD fluid; the slurry
contains materials that provide buoyancy of the slurry within the
PAD fluid; the buoyancy providing materials include at least one of
polymer particles, hollow beads, ceramic materials, porous
particles, fibers and foaming agents; the carrier fluid is the PAD
fluid; the carrier fluid is immiscible with the PAD fluid; the
carrier fluid is miscible with the PAD fluid; and the carrier fluid
is at least one of a drilling mud or a completion brine.
[0007] Yet another embodiment of the invention, is a method of
treating a formation penetrated by a wellbore including the steps
of: providing a quantity of particles containing delayed
water-swelling particles formed at least in part from a
water-swelling material; forming a slurry of the particles with a
carrier fluid; and introducing the slurry into the wellbore during
or subsequent to introduction of a PAD fluid of a fracturing
treatment, in which the carrier fluid of the slurry has a specific
gravity that is at least one of greater or less than the specific
gravity of the PAD fluid. In various versions of this embodiment:
the slurry contains materials that provide buoyancy of the slurry
within the PAD fluid; the buoyancy providing materials include at
least one of polymer particles, hollow beads, ceramic materials,
porous particles, fibers and foaming agents; the carrier fluid is
the PAD fluid; the particles include non-water-swelling particles;
non-water-swelling particles of at least two different size
distributions are used in which the mean particle size of the
larger non-water-swelling particles is at least 1.5 times greater
than that of the smaller non-water-swelling particles; the
non-water-swelling particles include coarse particles having a
particle size of from about 0.2 mm to about 2.35 mm and at least
one of fine particles having a particle size of less than about 0.1
mm and medium particles having a particle size of from about 0.1 mm
to less than about 0.2 mm; the water-swelling material is at least
one of a clay and a superabsorbing material; the clay is selected
from bentonite, montmorillonite, smectite, nontronite, beidellite,
perlite and vermiculite clays and combinations of these, and the
superabsorbing material is selected from polymers and copolymers of
acrylate, acrylic acid, amide, acrylamide, saccharides, vinyl
alcohol, urethane, and combinations of these materials; the delayed
water-swelling particles are formed from particles having a core of
water-swelling material with a coating of water degradable
material; the water degradable material is a solid polymer acid
precursor, for example polylactic acid; the delayed water-swelling
particles contain a weighting material; the weighting material is
selected from silicates, aluminosilicates, barite, hematite,
ilmenite, manganese tetraoxide, manganosite, iron, lead, aluminum
and combinations of these; the delayed water-swelling particles are
formed from particles having an inner core of proppant material
with a layer of the delayed water absorbent material formed around
the proppant material; the delayed water-swelling particles are
formed from superabsorbing polymer particles that are crosslinked
at the surface to reduce penetration by water; the superabsorbing
polymer particles are further coated with at least one of (1) a
layer or layers of water degradable material and (2) a layer or
layers of non-water-degradable, non-water absorbing encapsulating
material; the carrier fluid is immiscible with the PAD fluid; and
the carrier fluid is miscible with the PAD fluid.
[0008] A further embodiment of the invention is a method of
treating a formation penetrated by a wellbore including the steps
of: providing a quantity of delayed water-swelling particles having
a core of a water-swelling material in which the core has a coating
substantially surrounding the core that temporarily prevents
contact of water with the water-swelling material, the coating
being formed from at least one of (1) a layer or layers of water
degradable material and (2) a layer or layers of
non-water-degradable, non-water absorbent encapsulating material;
forming a slurry of the particles with a carrier fluid; and
introducing the slurry of particles into the wellbore of the
formation. In various versions of this embodiment:
non-water-swelling particles are provided with the delayed
water-swelling particles; the slurry of particles is positioned
within a fracture of the formation; the water-swelling material is
capable of absorbing at least the water-swelling material's weight
of water; the non-water-swelling particles have a particle size of
from about 0.035 mm to about 2.35 mm; non-water-swelling particles
of at least two different size distributions are used in which the
mean particle size of the larger non-water-swelling particles is at
least 1.5 times greater than that of the smaller non-water-swelling
particles; the non-water-swelling particles include coarse
particles having a particle size of from about 0.2 mm to about 2.35
mm and at least one of fine particles having a particle size of
less than about 0.1 mm and medium particles having a particle size
of from about 0.1 mm to less than about 0.2 mm; the water-swelling
material is a superabsorbent material that has been surface
cross-linked to further delay swelling; the particles have a
specific gravity that is at least one of greater or less than the
specific gravity of the carrier fluid; the water-swelling material
is at least one of a clay and a superabsorbing material; the clay
is selected from bentonite, montmorillonite, smectite, nontronite,
beidellite, perlite and vermiculite clays and combinations of
these, and the superabsorbing material is selected from polymers
and copolymers of acrylate, acrylic acid, amide, acrylamide,
saccharides, vinyl alcohol, urethane, and combinations of these
materials; the delayed water-swelling particles are formed from
particles having a core of water-swelling material with a coating
of water degradable material; the water degradable material is a
solid polymer acid precursor, for example polylactic acid; the
delayed water-swelling particles contain a weighting material; the
weighting material is selected from silicates, aluminosilicates,
barite, hematite, ilmenite, manganese tetraoxide, manganosite,
iron, lead, aluminum and combinations of these; the delayed
water-swelling particles are formed from particles having an inner
core of proppant material with a layer of the delayed water
absorbent material formed around the proppant material; the delayed
water-swelling particles are formed from superabsorbing polymer
particles that are crosslinked at the surface to reduce penetration
by water; the slurry is introduced into the wellbore during or
subsequent to introduction of a PAD fluid of a fracturing
treatment; the carrier fluid of the slurry has a specific gravity
that is at least one of greater or less than the specific gravity
of the PAD fluid; the slurry contains materials that provide
buoyancy of the slurry within the PAD fluid; the buoyancy providing
materials include at least one of polymer particles, hollow beads,
ceramic materials, porous particles, fibers and foaming agents; the
carrier fluid is the PAD fluid; the carrier fluid is immiscible
with the PAD fluid; the carrier fluid is miscible with the PAD
fluid; and the carrier fluid is at least one of a drilling mud or a
completion brine.
[0009] Yet a further embodiment of the invention is a method of
treating a subterranean formation immediately surrounding a
wellbore penetrating the formation to reduce lost fluid circulation
during drilling operations including the steps of: providing a
quantity of particles containing delayed water-swelling particles
formed at least in part from a water-swelling material; forming a
slurry of the particles with a carrier fluid; and introducing the
slurry into the wellbore at a pressure sufficient to fracture a
portion of the formation. In various aspects of this embodiment:
the carrier fluid is at least one of a drilling mud or a completion
brine; the delayed water-swelling particles are superabsorbing
particles in a carrier fluid of one of a non-aqueous fluid, an
emulsion and an aqueous metal salt solution that delays absorption
of water; the particles also include non-water-swelling particles;
non-water-swelling particles of at least two different size
distributions are used in which the mean particle size of the
larger non-water-swelling particles is at least 1.5 times greater
than that of the smaller non-water-swelling particles; the
non-water-swelling particles include coarse particles having a
particle size of from about 0.2 mm to about 2.35 mm and at least
one of fine particles having a particle size of less than about 0.1
mm and medium particles having a particle size of from about 0.1 mm
to less than about 0.2 mm; the water-swelling material is at least
one of a clay and a superabsorbing material; the clay is selected
from bentonite, montmorillonite, smectite, nontronite, beidellite,
perlite and vermiculite clays and combinations of these, and the
superabsorbing material is selected from polymers and copolymers of
acrylate, acrylic acid, amide, acrylamide, saccharides, vinyl
alcohol, urethane, and combinations of these materials; the delayed
water-swelling particles are formed from particles having a core of
water-swelling material with a coating of water degradable
material; the water degradable material is a solid polymer acid
precursor, for example polylactic acid; the delayed water-swelling
particles are formed from particles having an inner core of
proppant material with a layer of the delayed water absorbent
material formed around the proppant material; the delayed
water-swelling particles are formed from superabsorbing polymer
particles that are crosslinked at the surface to reduce penetration
by water; the method further includes circulating a drilling fluid
within the wellbore during drilling after introduction of the
slurry; the method further includes introducing a cement into the
wellbore after introduction of the slurry; and the method further
includes introducing a further well treatment fluid into the
wellbore after introduction of the slurry.
[0010] A further embodiment of the invention is a method of
positioning materials in a formation penetrated by a wellbore
containing the steps of: providing a quantity of particles; forming
a slurry of the particles with a carrier fluid; introducing the
slurry of particles into the wellbore of the formation; and
introducing a second fluid into the wellbore of the formation prior
to or subsequent to the slurry, in which the carrier fluid of the
slurry has a specific gravity that is at least one of greater or
less than the specific gravity of the second fluid. In variations
of this embodiment: the slurry contains materials that provide
buoyancy of the slurry within the second fluid; the buoyancy
providing materials include at least one of polymer particles,
hollow beads, ceramic materials, porous particles, fibers and
foaming agents; the carrier fluid is immiscible with the second
fluid; and the carrier fluid is miscible with the second fluid.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] For a more complete understanding of the present invention,
reference is now made to the following description taken in
conjunction with the accompanying figures, in which:
[0012] FIG. 1 is a graph showing permeabilities of sand and a
sand/delayed superabsorbent mixture over time;
[0013] FIG. 2 is a plot of permeability for a sand/delayed
superabsorbent mixture over time at constant fluid flow rate;
and
[0014] FIG. 3 is plot of permeability for a sand/delayed bentonite
composite mixture over time at a constant fluid flow rate.
DETAILED DESCRIPTION
[0015] Delayed water-swelling materials can be prepared from
particles having a core containing a water-swelling material that
is surrounded by a coating that temporarily prevents contact of
water with the water-swelling material. The water-swelling material
may be capable of absorbing at least the water-swelling material's
weight of water. In particular, the water-swelling material may be
capable of absorbing from at least about one to 600 hundred times
the water-swelling material's weight of water, more particularly
from about 10 to about 400 times the water-swelling material's
weight of water, and still more particularly from about 40 to about
200 times the water-swelling material's weight of water.
[0016] It should be understood that throughout this specification,
when a concentration or amount range is described as being useful,
or suitable, or the like, it is intended that any and every
concentration or amount within the range, including the end points,
is to be considered as having been stated. Furthermore, each
numerical value should be read once as modified by the term "about"
(unless already expressly so modified) and then read again as not
to be so modified unless otherwise stated in context. For example,
"a range of from 1 to 10" is to be read as indicating each and
every possible number along the continuum between about 1 and about
10. In other words, when a certain range is expressed, even if only
a few specific data points are explicitly identified or referred to
within the range, or even when no data points are referred to
within the range, it is to be understood that the inventors
appreciate and understand that any and all data points within the
range are to be considered to have been specified, and that the
inventors have possession of the entire range and all points within
the range.
[0017] Of particular use for the water-swelling materials are
superabsorbing materials. Superabsorbing materials are formed from
polymers that are water soluble but that have been internally
crosslinked into a polymer network to an extent that they are no
longer water soluble. Such materials have the tendency to swell or
absorb water. Examples of superabsorbing materials are described in
U.S. Pat. Nos. 4,548,847; 4,725,628 and 6,841,229 and in U.S.
Patent Application Publication Nos. US2002/0039869A1 and
US2006/0086501A1, each of which is herein incorporated by reference
in its entirety. Non-limiting examples of superabsorbing materials
include crosslinked polymers and copolymers of acrylate, acrylic
acid, amide, acrylamide, saccharides, vinyl alcohol,
water-absorbent cellulose, urethane, and combinations of these
materials. Particles of the superabsorbing material may have an
unswollen particle size of from about 50 microns to about 1 mm or
more.
[0018] Other water-swelling materials that are not superabsorbent
materials as defined above may also be used. These may include
natural water-swelling materials such as water-swelling clays.
Non-limiting examples of water-swelling clay materials include
bentonite, montmorillonite, smectite, nontronite, beidellite,
perlite and vermiculite clays and combinations of these. Such
non-superabsorbent, water-swelling materials may have an unswollen
particle size of from about 50 microns to about 1 mm or more, but
typically less than 2 mm.
[0019] The water-swelling materials may be used to form a composite
core wherein the water-swelling materials are combined with other
materials. These may include weighting agents to adjust the
specific gravity of the material. Examples of weighting agents may
include, but are not limited to, silicates, aluminosilicates,
barite, hematite, ilmenite, manganese tetraoxide (such as that
available commercially as Micromax from Elkem, Oslo, Norway),
manganosite, iron, lead, aluminum and other metals. Bentonite is
particularly useful as the water-swelling material when used in
combination with these weighting materials. The weighting agents
may be used in an amount of from 0 to about 70% by weight of the
composite particle. For certain applications binders may be used
with the weighting agents. Examples of binder materials include
thermoplastic materials, such as polystyrene, polyethylene,
polymethylmethacrylate, polycarbonate, polyvinylchloride, etc. The
binder materials may also include thermosetting materials, such as
phenol-formaldehyde, polyester, epoxy, carbamide and other resins.
Waxes may also be used as a binder material. The amount of binder
used may be just enough to provide a coating so that the materials
adhere together.
[0020] Other core materials may include proppants wherein the
proppant constitutes an inner core and the water-swelling material
forms an outer layer that surrounds the proppant. Such coated
proppants have mechanical strength as well as swelling capacity.
Examples of proppant materials include ceramic, glass, sand,
bauxite, inorganic oxides (e.g. aluminum oxide, zirconium oxide,
silicon dioxide, bauxite), etc. The coated proppant may be prepared
by immersing the proppant into a solution or emulsion of the
superabsorbant material and allowing the solvent to evaporate.
Heating may be used to evaporate the solvents. Typical drying
temperatures may be from about 110.degree. C. to about 150.degree.
C. The solvents may be aprotic organic solvents, such as hexanes,
heptanes and other saturated and unsaturated hydrocarbons. The
coating thickness can be varied by adjusting the coating time
and/or concentration of the dissolved superabsorbent.
[0021] The above-described method of coating proppant may have
particular application to proppant materials of smaller size such
as from about 0.3 mm to about 1 mm. Larger proppant sizes of from 1
mm or greater may be coated with dry superabsorbants. In such
instances, the proppant particles may be immersed in a binder
solution and the particles, being wet, are crumbed in milled
(typically less than 200 micron) superabsorbent powder, which
sticks to the proppant particle surface. The particles are then
allowed to dry so that the proppant particles are covered with the
superabsorbent powder.
[0022] For non-superabsorbing water-swelling materials, the
water-swelling material coating may be applied in a fluidized bed
coating procedure.
[0023] To provide delayed swelling of the water-swelling materials,
the water-swelling material particle core, including composite
water-swelling particle cores such as those that include weighting
agents and/or proppant materials, may be provided with a coating or
coatings that temporarily prevent contact of the water-swelling
material with water or aqueous fluids when subjected thereto. The
coating may be formed from a water degradable material that
eventually degrades in the presence of water. As used herein, the
expression "water degradable" or similar expression is meant to
encompass the characteristic of the material to decompose, such as
by dissolution, hydrolyzing, depolymerization, breaking apart of
chemical bonds, and the like, upon exposure to water under selected
conditions such that the material fails as a barrier.
[0024] An encapsulating layer may also be used. As used herein, the
term "encapsulating" when used in describing the coating materials
or layers is meant to be distinguished from the water degradable
material coatings in that the encapsulating material is
non-water-degradable or may have only limited degradability in
water so that the encapsulating coating must be mechanically broken
or removed or which may be degradable primarily in oil (non-water)
to allow contact of the water-swelling material with water. As used
herein, the encapsulating material does not include mineral oxide
(e.g. silica, aluminum) materials or resins or other materials that
degrade primarily in response to downhole temperature
conditions.
[0025] Of particular use for the water degradable materials are
solid polymer acid precursors. These are solid polymers or
oligomers of certain organic acids that hydrolyze or depolymerize
under known and controllable conditions of temperature, time and pH
to form their monomeric organic acids. As used herein, these
materials are referred to as "solid polymer acid precursors." These
materials are typically solids at room temperature.
[0026] One example of a suitable solid acid-precursor is the solid
cyclic dimer of lactic acid (known as "lactide"), which has a
melting point of 95.degree. C. to 125.degree. C., (depending upon
the optical activity). Another is the polymer of lactic acid,
(sometimes called a polylactic acid (or "PLA"), or a polylactate,
or a polylactide). Another example is the polymer of glycolic acid
(hydroxyacetic acid), also known as polyglycolic acid ("PGA"), or
polyglycolide. Another example is the solid cyclic dimer of
glycolic acid (known as "glycolide"), which has a melting point of
about 86.degree. C. Other materials suitable as solid
acid-precursors are all those polymers of glycolic acid with itself
or other hydroxy acids, such as are described in U.S. Pat. Nos.
4,848,467; 4,957,165; and 4,986,355, each of which is herein
incorporated by reference in its entirety.
[0027] Many of these polymers are essentially linear. The degree of
polymerization of the linear polylactic acid can vary from a few
units (e.g. 2-10) (oligomers) to several thousands (e.g.
2000-5000). The polymers may also include some cyclic structures,
including cyclic dimers. In general, the degree of polymerization
of these cyclic structures is smaller than that of the linear
polymers.
[0028] These solid polymer acid precursors may be homopolymers,
copolymers, and block copolymers of the above-described materials.
As used herein, "homopolymer(s)" may contain less than about 0.1%
by weight of other comonomers. As used with reference to polylactic
acid, "homopolymer(s)" is meant to include polymers of pure
D-lactic acid, pure L-lactic acid and/or mixtures or copolymers of
pure D-lactic acid and pure L-lactic acid. As used herein,
"copolymer(s)" may refer to both copolymers and block copolymers.
Combinations or mixtures of the above-described homopolymers and/or
copolymers may also be used.
[0029] Other examples of polyesters of hydroxycarboxylic acids that
can be used as solid polymer acid precursors are the polymers of
hydroxyvaleric acid (polyhydroxyvalerate), hydroxybutyric acid
(polyhydroxybutyrate) and their copolymers with other
hydroxycarboxylic acids. Polyesters resulting from the ring opening
polymerization of lactones such as epsilon caprolactone
(polyepsiloncaprolactone) or copolymers of hydroxyacids and
lactones can also be used.
[0030] Polyesters obtained by esterification of other hydroxyl
containing acid containing monomers such as hydroxyaminoacids can
also be used as the solid polymer acid precursors. Common
aminoacids are L-aminoacids. Among the most common aminoacids the
three that contain hydroxyl groups are L-serine, L-threonine, and
L-tyrosine. These aminoacids can be polymerized to yield polyesters
at the appropriate temperature and using appropriate catalysts by
reaction of their alcohol and their carboxylic acid group.
[0031] A general structure for the above-described homopolyesters
is:
H--{O--[C(R1,R2)].sub.x-[C(R3,R4)].sub.y-C.dbd.O}.sub.2--OH (1)
where, R1, R2, R3, R4 is either H, linear alkyl, such as CH.sub.3,
CH.sub.2CH.sub.3 (CH.sub.2).sub.nCH.sub.3, branched alkyl, aryl,
alkylaryl, or a functional alkyl group (bearing carboxylic acid
groups, amino groups, hydroxyl groups, thiol groups, or
others),
[0032] x is an integer between 1 and 11,
[0033] y is an integer between 0 and 10, and
[0034] z is an integer between 2 and 50,000.
[0035] NatureWorks LLC, Minnetonka, Minn., USA, produces solid
cyclic lactic acid dimer called "lactide" and from it produces
lactic acid polymers, or polylactates, with varying molecular
weights and degrees of crystallinity, under the generic trade name
NATUREWORKS.TM. PLA. Those available from NatureWorks LLC typically
have crystalline melt temperatures of from about 120.degree. C. to
about 170.degree. C., but others are obtainable. Poly(d,l-lactide)
is available from Bio-Invigor, Beijing and Taiwan, with weight
average molecular weights of up to 500,000. Polylactide products,
such as poly(l-lactide), of even higher weight average molecular
weights are also available. Bio-Invigor also supplies polyglycolic
acid (also known as polyglycolide) and various copolymers of lactic
acid and glycolic acid, often called "polyglactin" or
poly(lactide-co-glycolide).
[0036] The extent of the crystallinity can be controlled by the
manufacturing method for homopolymers and by the manufacturing
method and the ratio and distribution of lactide and glycolide for
the copolymers. Additionally, the chirality of the lactic acid used
also affects the crystallinity of the polymer. Polyglycolide can be
made in a porous form.
[0037] The rates of the hydrolysis reactions of all these materials
are governed by the molecular weight, the crystallinity (the ratio
of crystalline to amorphous material), the physical form (size and
shape of the solid), and in the case of polylactide, the amounts of
the two optical isomers. Some of the polymers dissolve very slowly
in water before they hydrolyze. (The naturally occurring L-lactide
forms partially crystalline polymers; synthetic D/L-lactide forms
amorphous polymers.) Amorphous regions are more susceptible to
hydrolysis than crystalline regions. Lower molecular weight, less
crystallinity and greater surface-to-mass ratio all result in
faster hydrolysis. Hydrolysis is accelerated by increasing the
temperature, by adding acid or base, or by adding a material that
reacts with the hydrolysis product(s).
[0038] To coat the particle core containing the water-swelling
material, the solid polymer acid precursor may be physically
dissolved in an organic solvent. Solvents that may be suitable for
physically dissolving the solid polymer acid precursors include,
but are not limited to, alcohols, ketones, esters, ethers, and
combinations of these. Examples of suitable solvents include
acetone, ethylacetate, butylacetate, toluene, dibasic esters, light
petroleum distillates, ethanol, isopropanol, acetonitrile and
combinations of these.
[0039] By immersing the particle core containing the water-swelling
material in a solution of the dissolved solid polymer acid
precursor and allowing the solvent to evaporate, a coating of the
solid polymer acid precursor can be formed that surrounds the
particle core. The thickness of the coating can be varied by
adjusting the coating agent concentration in the immersion
solution. The coating may also be applied in a fluidized bed
wherein the coating thickness is varied by adjusting exposure time
and concentration.
[0040] Additionally, several layers of the solid polymer acid
precursor coating may be applied by this technique. This may be
accomplished by providing a protective layer to a previously
applied coating to prevent the coating's dissolution during
recurring immersion of the particle into solution of the solid
polymer acid precursor. The protective material may be an oil,
plastificator or viscous solvent that does not dissolve the coating
material or dissolves it very slowly. Examples of such materials
may include glycerin, ethyleneglycol, organic oils, silicones,
esters of phthalic acid and combinations of these. To protect the
previously applied coating it is enough to treat the particles with
the protective material between the repeating of the immersion
coating of the particle as previously described. This may be
carried out any number of times to provide the desired thickness of
the coating.
[0041] The degree of delay in swelling provided by the coating for
the particles can be determined by performing simple tests using
water or fluids under conditions that simulate those that are
expected to be encountered in the particular application or
treatment for which the particles are to be used. The delayed
water-swelling particles can be tailored with a sufficient coating
or treatment to provide the desired degree of delay in swelling
based upon these tests.
[0042] The water-swelling core material may also be encapsulated by
a non-water-degradable, non-water absorbing coating that can be
removed mechanically or broken. Examples of suitable encapsulating
materials may include natural gums (e.g. gum acacia, gum arabic,
locust bean gum); polysaccharides such as modified starches (e.g.
starch ethers and esters, and enzyme-treated starches) or cellulose
compounds (e.g. hydroxymethylcellulose or carboxymethylcellulose);
polysaccharides; proteins, such as casein, gelatin, soy protein and
gluten, and synthetic film-forming agents, such as polyvinyl
alcohol, polyvinyl pyrrolidone, carboxylated styrene, non-water
absorbent polyvinyl alcohol, polyvinyl pyrrolidone, polyvinylidene
chloride, and mixtures of these. These and other suitable
encapsulating materials may include those that are described in
U.S. Pat. Nos. 3,952,741; 3,983,254; 4,506,734; 4,658,861;
4,670,166; 4,713,251; 4,741,401; 4,770,796; 4,772,477; 4,933,190;
4,978,537; 5,110,486; 5,164,099; 5,373,901; 5,505,740; 5,716,923;
5,910,322 and 5,948,735, each of which is incorporated herein by
reference. Carbon-based polymers may also be used as an
encapsulating material. These protective materials may be broken
upon fracture closing or other mechanisms that cause breakage of
the coating.
[0043] In another embodiment, delayed water-swelling particles can
be formed by restricting the mobility of the polymer chains at the
surface of the superabsorbing particles. This is accomplished by
surface crosslinking the polymer particles with a crosslinking
agent. Known crosslinking agents include metal salts or complexes,
particularly those that are transition metal based. Further
crosslinking of polymer chains in the surface of the superabsorbent
granule may be accomplished by refluxing the superabsorbing
particle in an alcohol (such as isopropanol) solution of a
transition metal complex; in particular complexes of zirconium and
titanium may be used. The crosslinking surface treatment delays
water penetration into the body of the water-swelling particle.
[0044] In certain applications, the delayed water-swelling
particles may be provided by methods other than through the use of
surface coatings or treatment. These may include the use of a
non-aqueous carrier fluid or emulsions wherein the water-swelling
material is carried in the oil phase of an oil and water emulsion,
which may be an oil-in-water or water-in-oil emulsion.
Additionally, the use of aqueous metal salt solutions, such as
halogenides of alkali and alkali-earth metals (e.g. sodium
chloride) with the superabsorbing materials is known to delay the
swelling of the superabsorbing material.
[0045] Combinations of the above-described methods for delaying
swelling of the water-swelling material may be used. For example,
superabsorbing materials that have undergone surface crosslinking
may be coated with a coating or coatings of water degradable
materials or non-water-degradable encapsulating materials or both.
Water-swelling materials may be coated with coatings of water
degradable materials and non-water-degradable encapsulating
materials. These materials may be used in non-aqueous carriers or
in the oil phase of an oil and water emulsion.
[0046] The above-described delayed water-swelling particles may be
used alone or in combination with other materials for various
applications. The delayed water-swelling particles may be of
various shapes and sizes, which may be dependent upon the
particular application for which they are used.
[0047] The delayed water-swelling particles have particular
application in the treatment of subterranean formations such as
those formations of oil and gas wells. The delayed water-swelling
particles may be used in combination with other particles. These
may include inert, non-water-swelling particles that may be
non-malleable particles such as ceramic, glass, sand, bauxite,
inorganic oxides (e.g. aluminum oxide, zirconium oxide, silicon
dioxide, bauxite), etc.
[0048] In particular applications, the delayed water-swelling
particles may be used in combination with non-water-swelling
particles of different size distributions. The use of such
particles of different size distributions to reduce formation
permeability is described in U.S. Pat. No. 7,004,255 to Boney,
entitled "Fracture Plugging," and which is herein incorporated by
reference in its entirety. As described therein, particles of
different size distributions are used in combination to fill a
fracture. It is well known that a region filled with regularly
arranged spheres of equal size will have a void volume of about
36%. Furthermore, if a second set of equal-sized spheres that are
about one tenth the size of the first set are included, the smaller
spheres will tend to reside in the voids between the larger
spheres, and the resulting void volume will be about 23%. Finally,
if a third set of equal-sized spheres that are about one tenth the
size of the second set are included, the final void volume will be
about 15%.
[0049] In the present invention, the different sized
non-water-swelling particles may have a particle size of from about
0.035 mm to about 2.35 mm or more. The non-water-swelling particles
may have a particle size distribution wherein the mean particle
size of the larger non-water-swelling particles is at least about
1.5 times greater than that of the smaller non-water-swelling
particles. The non-water-swelling particles of different sizes may
include "coarse" particles having a particle size of from about 0.2
mm to about 2.35 mm, "medium" particles having a particle size of
from about 0.1 mm to less than about 0.2 mm and "fine" particles
having a particle size of less than about 0.1 mm. If two sizes are
used instead of three, they could be "coarse" and "medium,"
"medium" and "fine", or "coarse" and "fine." Although the ranges of
the definitions of "coarse", "medium" and "fine" have been given as
contiguous, the actual sizes used may not be contiguous. For
example, although the coarse particles may be from about 0.2 mm to
approximately 2.35 mm and medium particles may be from about 0.1 mm
to about 0.2 mm in diameter, actual sizes used in a treatment might
be about 1 to about 2 mm and about 0.1 to about 0.2 mm,
respectively. Additionally, different size distributions of
particle sizes within each of the coarse, medium and fine particle
sizes may also be used.
[0050] A mixture of non-water-swelling particles of from about 30
to about 95% by total weight of non-water-swelling particles of the
coarse particles, 0 to about 30% by total weight of
non-water-swelling particles of the medium particles, and 0 to
about 20% by total weight of non-water-swelling particles of the
fine particles may be suitable in many applications. These
guidelines are generally accurate for the normal situation in which
the particles are not perfect spheres, are not uniform in size, and
are not perfectly packed.
[0051] The delayed water-swelling particles may be used in
combination with the non-water-swelling particles in an amount of
from about 0.5% to about 50% or more by total weight of particles.
The delayed water-swelling particles may be premixed with the
non-water-swelling particles or may be added separately.
[0052] In certain applications utilizing encapsulated
water-swelling materials, the particle size of the unswollen
water-swelling particles may be the same or within the same range
as the largest non-water-swelling particles. This facilitates the
most efficient mechanical release, as smaller water-swelling
particles may tend to pack in the interstitial space between the
large non-water-swelling particles so that the encapsulating layer
is never broken. In other applications, such as in drilling
applications, where an encapsulating layer is not used, the
water-swelling particles may be smaller than the largest non-water
swelling materials.
[0053] In hydraulic fracturing of subterranean formations of oil or
gas wells, the delayed water-swelling particles may be used alone
or in combination with non-water-swelling particles to treat the
upper and/or lower boundaries of the fracture where insufficient
stress barriers may result in vertical fracture growth or where the
fracture grows into adjacent water or undesirable gas bearing
zones. The non-water-swelling proppant particles and water-swelling
particles create mechanically sound barriers that are able to
isolate upper and lower zones from pressure developed in the
fracture during treatment, with the water-swelling materials
eventually sealing the pore spaces between the non-water-swelling
particles, thus creating an impermeable artificial barrier.
[0054] To create artificial barriers that prevent fracture growth
into undesirable areas, the particles may be added to the
fracturing fluid and pumped into the fracture during the hydraulic
fracturing treatment. The mixture may be pumped at the beginning of
the treatment in the PAD or immediately after the PAD and prior to
the main proppant stages.
[0055] The particles are added to a carrier fluid to form a slurry.
The particles may have a density that is the same, higher or lower
than that of the carrier fluid. Because delayed water-swelling
particles are used, aqueous or water-based fluids may be used as
the carrier fluid. The carrier fluid may be any fluid having
properties that allow the particulate materials to be transported
therein. It can be the same fluid as that employed as the PAD
fracturing fluid. Examples of suitable carrier fluids may include
water, oil, viscosified water (such as water based guar, modified
guar gel crosslinked with borate or organometallic compounds, or
water viscosified with a viscoelastic surfactant that forms
micelles), viscosified oil, emulsions, energized fluids (for
example with nitrogen or CO.sub.2 gas) and slick water (water
containing a small amount of polymer or viscoelastic surfactant
that serves primarily as a friction reducer rather than primarily
as a viscosifier).
[0056] In certain applications, such as drilling applications,
other materials may be present in the carrier fluid. These may
include such materials as xanthan gum, whelan gum, scleroglucan,
etc., as viscosifiers, as well as bentonite in aqueous solutions.
If a non-aqueous carrier fluid is used, viscosifiers may include
organophillic clays and phosphate esters.
[0057] Depending upon the desired area of placement of the
particles, the properties of the particles and the carrier fluid
may be varied. The carrier fluid may be miscible or immiscible with
the PAD fluid or other treatment fluids with which it is used. The
carrier fluid may have the same or substantially the same density
as the PAD or other treating fluid. The density of the carrier
fluid may also be adjusted so that its specific gravity is greater
or less than that of the PAD fracturing fluid or other treating
fluid. In this way, the particles can be placed along upper and
lower boundaries of the fracture. Carrier fluids with higher
specific gravities than the PAD fluid will tend to finger or slump
along with the carried solids through the PAD fluid due to gravity
driven convection fluid flow so that the slurry is placed at the
bottom of the fracture. The properties of the carrier fluid may be
modified through the use of gelling agents, pH adjustors or the
addition of breakers to provide the desired characteristics. For
example, for some crosslinkers, lower pH eases carrier fluid
fingering through the PAD. Density can also be adjusted with
weighing agents, as discussed previously.
[0058] Similarly, carrier fluids with lower specific gravities than
the PAD fluid may be used. Fluids with lower densities may include
light fractions of oil. Carrier fluids with lower specific
gravities may also be provided by the inclusion of light-weight
materials or particles within the carrier fluid. These may include
such substances as light-weight ceramic materials, hollow beads,
porous particles, fibers and/or foaming agents, polymer particles
(e.g. polypropylene particles, which are commercially available
with densities of less than 1 g/cm.sup.3), etc. Due to the
difference in densities, the carrier fluid containing the delayed
water-swelling particles, with or without non-water-swelling
proppant particles, will be buoyant in the PAD fluid and will rise
to the upper portion of the fracture.
[0059] If it is necessary that the carrier fluid be of a lower
viscosity than is sufficient for a safe placement of the delayed
water-swelling mixture, fibers may be added. These may be formed
from carbon- or silicon-based polymers. The fibers facilitate
suspending of the particles in the carrier fluid and have a
negligible effect on the proppant pack permeability after the
fracture closes. The concentration and nature of the fibers may be
tailored to both assist particle suspension and to form a less
permeable barrier along the lower and/or upper boundary of the
fracture.
[0060] The delayed water-swelling particles with or without
non-water-swelling particles of the same or of different size
distributions, as has been described, may be placed along the upper
and lower boundaries of the fracture. Such mixture is pumped during
or right after the PAD treatment. The carrier fluid/particle
mixture may be pumped in separate stages, with the higher specific
gravity carrier fluid mixture being pumped prior to or after the
lower specific gravity mixture. The delayed water-swelling
particles, including those composite particles that contain
weighting agents and the like, may be placed by radial flow that is
induced in the fracture early in the treatment and carries the
delayed water-swelling particles and other particles of the mixture
in both upward and downward directions. Particles are bridged in
the lower and upper extremities of the fracture. The proppants or
non-water-swelling particles provide dense mechanically stable
barriers. Once in place, the aqueous carrier fluid or water from
water producing zones eventually causes the water-swelling material
of the particles to swell, providing further reductions in
permeability and rendering additional isolation properties. Because
swelling of the water-swelling particles is delayed, preliminary
swelling is avoided thus facilitating placement of the particle
mixture within the extremities of the formation.
[0061] Following treatment of the formation with the artificial
bridging material formed by the delayed water-swelling particles
and/or mixtures, further PAD fluid may be pumped to provide further
fracturing of the formation, with the bridging material preventing
fracturing in non-producing zones. Alternatively, the treatment may
continue with proppant loading in a conventional manner. The use of
the delayed water-swelling particle materials and mixtures does not
require any changes in the main fracture treatment design and the
fracturing job can be conducted in a normal manner.
[0062] In another application, the delayed water-swelling
particles, with or without non-water-swelling particles of the same
or different size distributions, may be used in drilling operations
with drilling mud, in completion brines or in treating areas of the
formation immediately surrounding the wellbore. As was discussed
previously, in high permeable formations, such as sandstone, fluid
loss in fractures formed during drilling operations, which are
typically much narrower than those formed in hydraulic fracturing,
causes the drilling mud within the fracture to eventually dehydrate
so that the fracture is blocked by the mud particles and additives
and there is no pressure transmitted to the tip of the fracture and
therefore no further fracture growth. In shale and other low
permeable formations, there is limited or no fluid lost from the
drilling fluid so that the fracture tends to propagate.
[0063] By using the delayed water-swelling materials during
drilling operations in shale or other low permeability formations,
the same effect can be achieved. The delayed water-swelling
particles may be used in combination with proppant of the same or
different sizes, as has been discussed. The proppant particles used
in drilling operations may include calcium carbonate or sand
particles of the same or different size distributions. Other
particulate materials, such as carbon and graphite materials, may
be used. These may include those available commercially as G-SEAL
and G-SEAL-PLUS materials, from M-I Swaco, Houston, Tex., U.S.A.,
and angular resilient carbon materials, as described in U.S. Pat.
No. 7,066,285, and which may be available commercially as STEELSEAL
materials, from Halliburton Energy Services, Inc., Houston, Tex.,
U.S.A.
[0064] For drilling applications, particle sizes may tend to be
smaller, however, than those used in fracturing. In drilling
applications, particle sizes ranging from about 100 microns to
about 1000 microns, more particularly from about 100 microns to
about 500 microns, may be used. The particle mixture may be added
to a portion of the drilling mud or as a pill. Fractures adjacent
to the wellbore will be propped open and the water-swelling
material will absorb water as the mud flows along the fracture,
eventually dehydrating the drilling mud so that the fracture is
blocked off, providing a "stress cage" around the wellbore in these
areas and thus preventing further fracturing. This increases or
widens the mud weight window that may be used in drilling
operations. This method may also be used in high permeability
formations, as well, to reduce fracture growth in high permeability
formations.
[0065] In certain situations, the formation may be fractured
deliberately during drilling or in other operations. The particle
slurry may be introduced at a sufficient pressure to form fractures
intentionally in portions of the formation immediately surrounding
the wellbore. These fractures may be propped open with the
materials described to increase the hoop strength around the
wellbore, which allows, if necessary, the mud weight to be
increased to control the formation or formation pore pressure later
in the drilling process without re-fracturing the zone that has
been treated. This may allow drilling to proceed further before
running casing. Additionally, the treatment may facilitate
cementing operations and other subsequent treatment, with the
water-swelling particle treatment occurring just prior to
cementing, or other treatments wherein fluids are introduced into
the wellbore.
[0066] In drilling applications, the delayed water-swelling
material formed from encapsulating coatings that must be removed
mechanically may not be desirable due to the stresses such coated
particles may encounter during the drilling operations, which may
prematurely break or remove the encapsulating coating. Those other
methods described previously for providing a delayed water swelling
may be used, however. If treatment occurs as a pill, the
water-swelling particles may be carried in a non-aqueous carrier or
a highly saline aqueous fluid that delays swelling of the
superabsorbing particles.
[0067] The following examples serve to further illustrate the
invention:
EXAMPLES
Example 1
[0068] The influence of delayed water swelling particles on the
permeability of a sand pack was evaluated. Superabsorbing particles
in the form of partially crosslinked polyacrylate polymer particles
having a particle size of 0.2 to 1 mm, with an ability to absorb up
to 500 times their weight of water, marketed as AQUASORB 3995 KM,
available from Hercules Incorporated, Wilmington, Del., U.S.A.,
were coated with a coating of PLA. The PLA coating was applied in
an amount of approximately 25-35 wt. % of the coated superabsorbing
particle. The coating was applied by immersion of the
superabsorbent particle in a solution of the dissolved PLA.
[0069] The superabsorbing particles with the PLA coating were used
in combination with 20/40 mesh (0.84 mm/0.42 mm) sand. The coated
superabsorbing particles were used in an amount of 2.5% by total
weight of the mixture. Permeability was measured on a conductivity
apparatus at 90.degree. C. in a cell pressurized to approximately
4000 psi (27.6.times.10.sup.3 kPa) using a 2 wt. % KCl brine
solution at three different flow rates of 0.5 mL/min, 1 mL/min and
1.5 mL/min. The conductivity apparatus consisted of a 200,000 lbf
(890 kN) load press with automated hydraulic intensifiers and a
modified Hastelloy API conductivity cell with a 10 in.sup.2 (64.5
cm.sup.2) flow path. The apparatus was capable of attaining a
maximum closure stress of 200,000 psi (1.38.times.10.sup.6 kPa) and
a maximum temperature of 350.degree. F. (177.degree. C.). The
temperature of the conductivity cell was controlled by electrically
heated platens in contact with the sides of the cell. Rosemount
pressure transducers were used to measure the pressure drop across
the length of the fracture. A Mitutoyo digital caliper was used to
measure the fracture gap width. Quizix chromatography pumps were
used to pump the brine through the cell during flowback and
conductivity measurements. The pumps drew nitrogen-sparged 2 wt %
KCl brine from a 2 gallon (7.57 L) flowback reservoir. The brine
was nitrogen sparged to prevent the introduction of metal oxides
into the proppant pack. Before the brine entered the conductivity
cell, it was passed through a reservoir simulator and a silica
saturation system.
[0070] As a baseline, the permeability of a sand pack without the
water-swelling particles was determined at room temperature. A sand
pack containing the 2.5% by weight of the delayed superabsorbent
material was measured after approximately 30 minutes, 4 hours and
23 hours. The results are presented in Table 1 below.
TABLE-US-00001 TABLE 1 Time Conduc- Fracture of test, tivity
Permeability Width Temp Test hr:min (mDft) (Darcy) (mm) (.degree.
C.) Sand 20/40-mesh 0:30 2617 147 5.43 26 4:50 2193 123 5.43 26
23:10 2078 117 5.42 94 Sand 20/40-mesh + 0:45 369 20 5.53 26 2.5 wt
% Delayed 4:32 1.07 0.0622 5.24 94 Superabsorbent 23:20 1.00 0.0587
5.21 89
[0071] FIG. 1 shows the average permeability at the three different
flow rates from Example 1. The average permeability of the sand
pack using delayed superabsorbent was approximately 7 times less
than that of the baseline sand pack. After over four hours, the
average permeability dropped to approximately 0.05% of that of the
baseline permeability. After over 23 hours, a modest decrease of 6%
in average permeability was observed from that obtained at four
hours.
Example 2
[0072] A sand pack having the second composition of Example 1
(20/40-mesh sand plus 2.5 wt % Delayed Superabsorbent) was tested
at approximately 90.degree. C. and approximately 4000 psi
(27.6.times.10.sup.3 kPa) using a constant flow rate of 2 wt % KCl
brine at 1 mL/min. The results are presented in Table 2 below and
in FIG. 2. As can be seen in FIG. 2, permeability leveled off after
approximately 2 hours.
TABLE-US-00002 TABLE 2 Time Flow Rate Temp Fracture Width Viscosity
dP Conductivity Permeability (hr:min) (ml/min) (.degree. C.) (mm)
(cP) (kPa) (mDft) (Darcy) 0:56:00 3 26 5.385 0.8704 1.4661 328.8779
18.6150 1:22:00 3 41 5.385 0.6465 3.7107 96.5508 5.4649 2:00:00 1
67 5.385 0.4286 26.1941 3.0216 0.1710 2:26:00 1 79 5.385 0.3663
36.1432 1.8712 0.1059 3:00:00 1 87 5.385 0.3328 38.8057 1.5839
0.0897 3:26:00 1 87 5.385 0.3328 38.1529 1.5449 0.0874 4:00:00 1 93
5.385 0.3110 37.5781 1.5280 0.0865 4:26:00 1 94 5.385 0.3076
69.0800 0.8221 0.0465
Example 3
[0073] Delayed water-swelling particles using bentonite as the
water-swelling material were evaluated. The bentonite was combined
with a weighting agent of barite or hematite. The bentonite
composite particles were prepared according to the following
procedure: To a dry mixture of 80 wt % bentonite and 20 wt % of
barite or hematite, a 3 wt % solution of polyethylene in heptane
heated to 85.degree. C. was added with stirring until a dense
mixture was formed. The obtained mixture was placed into a syringe
and extruded into cylindrical particles, which were dried for 4-8
hours. The cylindrical particles were 2 mm in diameter and 4-7 mm
in length. The cylindrical particles were coated with PLA. The PLA
coating was applied in an amount of approximately 25-35 wt. % of
the composite particle. The coating was applied by immersion of the
particle in a solution of the dissolved PLA.
[0074] A mixture of 20/40 mesh (0.84 mm/042 mm) sand and the PLA
coated bentonite particles was tested in a 1/2 inch (1.27 cm)
Hassler sleeve-type conductivity apparatus at 1500 psi
(10.3.times.10.sup.3 kPa) confining pressure. The sample was packed
in a Hassler sleeve that utilized a soft Tygon.RTM. PVC tube with a
length of 0.57-0.60 m and an inner diameter of 1/2 inch (1.27 cm).
The soft sleeve was placed in a steel tube with an inner diameter
of 7/8 inch (2.22 cm) and outer diameter of 1 inch (2.54 cm). A
chromatographic pump was used to create confining stress by pumping
pure water inside the steel tube. The maximum confining stress that
could be used with the tube was 3,100 psi (21.3.times.10.sup.3
kPa). Another pump was used to create a flow of brine. Pressure
gauges at either end of the device measured differential pressure
drop. The maximum pressure drop was limited to the gauge pressure
range of 300 psi (2070 kPa). The distance between the pressure
ports was 0.466 m. Measurements were conducted at room
temperature.
[0075] The coated bentonite particles were used in an amount of
21.5% by total weight of the particle mixture. Brine (2 wt % KCl,
400 ppm Ca.sup.2+) was pumped at a flow rate of about 5 ml/min. The
permeability of the composite bentonite/sand pack was measured at
room temperature and provided a generally constant permeability of
approximately 38 D. The Hassler sleeve holder was disconnected and
then heated to approximately 60.degree. C. for 10 hours to
accelerate PLA coating removal. After the heat treatment, further
measurements were made with an observed 26 fold decrease in
permeability. The results are presented in Table 3 below and in
FIG. 3.
TABLE-US-00003 TABLE 3 Permeability (Darcy) Time Sand + 21.5 wt %
Coated (hr:min) Bentonite Composite 00:30 38 1:30 38 8:00 8 8:02 5
8:03 1.5 8:04 1.4
[0076] While the invention has been shown in only some of its
forms, it should be apparent to those skilled in the art that it is
not so limited, but is susceptible to various changes and
modifications without departing from the scope of the invention.
Accordingly, it is appropriate that the appended claims be
construed broadly and in a manner consistent with the scope of the
invention.
* * * * *