U.S. patent application number 12/808128 was filed with the patent office on 2010-10-21 for methods of contacting and/or treating a subterranean formation.
Invention is credited to James G. Carlson, Michael D. Crandall, Ignatius A. Kadoma, Dean Michael Willberg, Yong K. Wu.
Application Number | 20100263870 12/808128 |
Document ID | / |
Family ID | 40796084 |
Filed Date | 2010-10-21 |
United States Patent
Application |
20100263870 |
Kind Code |
A1 |
Willberg; Dean Michael ; et
al. |
October 21, 2010 |
METHODS OF CONTACTING AND/OR TREATING A SUBTERRANEAN FORMATION
Abstract
Methods of contacting a subterranean formation are described
which provide improved control or reduction of particulate
migration, transport or flowback in wellbores and reservoirs, and
which may do so without sacrificing substantial hydraulic
conductivity. One method comprises injecting into a well-bore
intersecting the subterranean formation a fluid composition
comprising a first component and a second component dispersed in a
carrier fluid, at least a portion of the first component or second
component being provided as at least one multicomponent article
having an aspect ratio greater than 1:1.1; forming a network
comprising the first component; and binding the network with the
second component.
Inventors: |
Willberg; Dean Michael;
(Salt Lake City, UT) ; Carlson; James G.; (Lake
Elmo, MN) ; Kadoma; Ignatius A.; (Cottage Grove,
MN) ; Wu; Yong K.; (Woodbury, MN) ; Crandall;
Michael D.; (North Oaks, MN) |
Correspondence
Address: |
MUETING, RAASCH & GEBHARDT, P.A.
P.O. BOX 581336
MINNEAPOLIS
MN
55458-1336
US
|
Family ID: |
40796084 |
Appl. No.: |
12/808128 |
Filed: |
December 5, 2008 |
PCT Filed: |
December 5, 2008 |
PCT NO: |
PCT/US08/85657 |
371 Date: |
June 14, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61013993 |
Dec 14, 2007 |
|
|
|
Current U.S.
Class: |
166/305.1 |
Current CPC
Class: |
E21B 43/04 20130101;
C09K 8/50 20130101; C09K 8/03 20130101; C09K 8/56 20130101; C09K
8/70 20130101; C09K 2208/08 20130101; C09K 8/74 20130101 |
Class at
Publication: |
166/305.1 |
International
Class: |
E21B 43/25 20060101
E21B043/25 |
Claims
1. A method of contacting a subterranean formation comprising:
injecting into a well-bore intersecting the subterranean formation
a fluid composition comprising a first component and a second
component dispersed in a carrier fluid, at least a portion of the
first component or at least a portion of the second component being
provided as at least one multicomponent article having an aspect
ratio greater than 1:1.1; forming a network comprising the first
component; and binding the network with the second component.
2. (canceled)
3. (canceled)
4. The method of claim 1 wherein the forming and binding are
performed subsequent to injecting.
5. The method of claim 1 further comprising modifying at least one
of the first or second components by at least one controlled
modification process after injection into the wellbore.
6. The method of claim 1 wherein at least some of the
multicomponent articles have a shape selected from hollow,
prismatic, cylindrical, lobed, rectangular, polygonal, dog-boned,
faceted, combinations of these, and mixtures thereof.
7. The method of claim 1 wherein at least some of the
multicomponent articles are different from other multicomponent
articles in the fluid composition.
8. (canceled)
9. The method of claim 1 wherein at least some multicomponent
articles comprise the first component and the second component, and
wherein other multicomponent articles comprise a third component
and a fourth component.
10. (canceled)
11. The method of claim 1 wherein at least some of the
multicomponent articles further comprise a third component.
12. (canceled)
13. The method of claim 1 wherein at least one of the first or
second components is an activated adhesive.
14. (canceled)
15. The method of claim 1 wherein one of the first component and
second component have a modulus of less than 3.times.10.sup.6
dynes/cm.sup.2 (3.times.10.sup.5 N/m.sup.2) at a frequency of about
1 Hz at a temperature greater than -60.degree. C.
16. The method of claim 1 wherein the fluid composition further
comprises proppant.
17. A method of contacting a subterranean formation comprising:
injecting into a well-bore intersecting the subterranean formation
a fluid composition comprising a first component and a second
component dispersed in a carrier fluid, wherein the first component
and the second component are provided as separate articles to the
carrier fluid separately prior to injection; forming a network
comprising at least one first component article in direct contact
with another first component article; and binding the network with
the second component.
18. The method of claim 17 further comprising modifying at least
one of the first or second components upon or after injection into
the wellbore.
19. The method of claim 18 wherein the modification process is
selected from chemical, physical, mechanical, radiation, and
combinations thereof.
20-23. (canceled)
24. The method of claim 17 wherein at least one of the first
component or second component is an activated adhesive.
25-32. (canceled)
33. A method of contacting a subterranean formation comprising:
injecting into a well-bore intersecting the subterranean formation
a fluid composition comprising a first component and a second
component dispersed in a carrier fluid; forming a network
comprising the first component; and binding the network with the
second component, wherein the second component is selected to be
tacky at a specific downhole temperature and have a modulus of less
than 3.times.10.sup.6 dynes/cm.sup.2 (3.times.10.sup.5 N/m.sup.2)
at a frequency of about 1 Hz at a temperature greater than
-60.degree. C.
34. The method of claim 33 wherein the first component and second
component are blended together.
35-37. (canceled)
38. The method of claim 1, wherein the contacting comprises pumping
under pressure into the well-bore.
39-50. (canceled)
51. A method of reducing migration of solids comprising: providing
a fluid composition into a well-bore, the well-bore intersecting a
subterranean formation, the fluid composition comprising a first
component and a second component dispersed in a carrier fluid, at
least one of the first component and second component having an
aspect ratio greater than 1:1.1, wherein the second component is
selected to be tacky at a specific downhole temperature and have a
modulus of less than 3.times.10.sup.6 dynes/cm.sup.2
(3.times.10.sup.5 N/m.sup.2) at a frequency of about 1 Hz at a
temperature greater than -60.degree. C.; forming a network
comprising the first component; binding the network with the second
component; and contacting the subterranean formation with the fluid
composition.
52-56. (canceled)
57. The method of claim 51 wherein the second component is an
activated adhesive.
58. (canceled)
59. The method of claim 51 further comprising modifying the second
component after providing the fluid composition into the
well-bore.
60-61. (canceled)
62. The method of claim 51 wherein the solids comprise formation
fines.
63. (canceled)
64. The method of claim 59 wherein second component is modified by
a process selected from temperature activation, chemical
activation, pressure activation, mechanical activation, curing,
exposure to electromagnetic fields, exposure to electromagnetic
radiation, exposure to ionizing radiation, physical entanglement,
degradation, concurrently application of at least two of these
processes, consecutive application of at least two of these
processes, and combinations thereof.
65.-67. (canceled)
Description
BACKGROUND
[0001] This disclosure relates to the recovery of hydrocarbons from
subterranean formations. More particularly, the disclosure relates
to methods of using fluid compositions to recover hydrocarbons from
subterranean formations.
[0002] Undesired transport or flowback of formation or particulate
solids during the production of oil or other fluids from a
subterranean formation can be a problem in production operations.
For example, transported particulate solids from the formation may
restrict flow in a wellbore, limiting or completely stopping
production of the fluid. Additionally, the solids being transported
may substantially increase fluid friction, thereby increasing
pumping requirements, and may cause significant wear in production
equipment, particularly in the pumps and seals used in the
production process. Finally, undesired particulate solids in a
recovered product fluid must be separated to render the product
fluid commercially useful.
[0003] In some instances, undesired particulate flowback may be the
result, not of formation characteristics, such as a lack of
consolidation, but of the flowback of proppant utilized in a
fracturing operation. When flowback of proppant occurs, the
proppant particles become undesirable contaminants in the manner of
any undesired formation particulate solids, since they can cause
the same operational difficulties.
[0004] Numerous procedures and compositions have been developed in
order to overcome the problem of undesirable particulate transport
or flowback. For example, in unconsolidated formations, it is
common practice to provide a filtration bed of gravel in the area
near the bottom of the wellbore to inhibit transport of
unconsolidated formation particulates in the wellbore fluids.
Typically, such so-called "gravel packing" operations involve the
pumping and placement of a quantity of gravel and/or sand having a
mesh size between 10 and 60 mesh (U.S. Standard Sieve Series) into
the unconsolidated formation adjacent the bottom of the wellbore.
In other instances, gravel or proppant particles may be bound
together to form a porous matrix, thus facilitating the filtering
out and retention of the bulk of the unconsolidated particles
transported to the wellbore area. Occasionally, the gravel
particles or proppant particles are resin-coated, the resin being
pre-cured or cured in situ by a flush of a chemical binding agent.
In other cases, binding agents have been applied to gravel
particles to form the porous matrix.
[0005] As will be evident, gravel packing can be an expensive and
elaborate procedure, and, unfortunately, does not completely
eliminate the production of formation particulates. Additionally,
some wellbores are not stable, and thus cannot be gravel
packed.
[0006] U.S. Pat. Nos. 5,330,095; 5,439,055; 5,501,275; and
5,782,300 provide a different approach for reducing particulate
flowback. These patents disclose the use of fibrous and other
materials, suitably dispersed in a porous pack, for inhibiting
particulate flowback. Materials employed include, but are not
limited to, fibers of glass, ceramics, carbon, and polymers, and
platelets of glass, metal, and polymers. So far as is currently
known, however, "multicomponent" fibers have not been used or
suggested for use in any downhole well servicing applications. By
"multicomponent" fibers we mean fibers that have two or more
distinct phases, regions, or chemical compositions; in other words,
two or more regions that are distinct either physically,
chemically, or both physically and chemically. Because
multicomponent fibers have at least two distinct regions they may
be engineered to have multiple beneficial properties, and these
properties can be tuned to a greater extent than that of a single
component material fiber. As one of many examples, the material in
the inner core of a core-sheath fiber can be selected for strength,
flexibility and robustness, while the outer layer can be selected
for its adhesive qualities.
[0007] Notwithstanding the efficacy of the approaches described in
previous patents using fibers for particulate solids transport
control, there is room for even greater efficiency in controlling
or inhibiting particulate solids transport at the beginning of,
during or after well treatments, and in other downhole treatment
operations. This disclosure, therefore, is directed to methods to
provide improved control or reduction of particulate migration,
transport or flowback at the beginning of, during, and after a
variety of well servicing operations, under a variety of
conditions. The present disclosure also addresses these problems in
the context of maintaining substantially the same hydraulic
conductivity in the formation.
SUMMARY
[0008] In accordance with the present disclosure, methods of
contacting a subterranean formation are described which provide
improved control or reduction of particulate migration, transport
or flowback in wellbores and reservoirs, and which may do so
without sacrificing substantial hydraulic conductivity.
[0009] One aspect of the disclosure are methods of contacting a
subterranean formation comprising: [0010] injecting into a
well-bore intersecting the subterranean formation a fluid
composition comprising a first component and a second component
dispersed in a carrier fluid, at least a portion of the first
component or at least a portion of the second component being
provided as at least one multicomponent article having an aspect
ratio greater than 1:1.1 (in some embodiments, greater than 1:5,
1:10, 1:50, 1:100, or even 1:150); [0011] forming a network
comprising the first component; and [0012] binding the network with
the second component.
[0013] Methods in accordance with this aspect of the disclosure
include those wherein the at least one multicomponent article has
an exposed outer surface at least a portion of which comprises at
least a portion of the first component. In certain embodiments, the
forming and binding may be performed subsequent to injecting. In
certain others embodiments, the methods further comprise modifying
at least one of the first or second components by at least one
controlled modification process. At least some of the
multicomponent articles may have a shape selected from hollow,
prismatic, cylindrical, lobed, rectangular, polygonal, dog-boned,
faceted, combinations of these, and mixtures thereof. Other methods
within this aspect include those wherein at least some of the
multicomponent articles are different from other multicomponent
articles in the same fluid composition injected into the wellbore,
wherein the difference may be in composition, shape, texture,
aspect ratio, physical properties, and the like, and any
combination of these. In certain embodiments, at least some of the
multicomponent articles may have a shape different from the other
multicomponent articles. In other embodiments, at least some
multicomponent articles may comprise the first component and the
second component, and other multicomponent articles may comprise a
third component and a fourth component. In certain embodiments, one
of the first and second components may be the same as one of the
third and fourth components. In yet other embodiments, at least one
of the first and second components may be an activated adhesive,
and in these embodiments the activated adhesive may selected from
pressure-sensitive adhesives, temperature-sensitive adhesives,
moisture-sensitive adhesives, and curing agent-sensitive adhesives.
In certain methods, one of the first component and second component
may be selected to be tacky at a specific downhole temperature and
have a modulus of less than about 3.times.10.sup.6 dynes/cm.sup.2
(3.times.10.sup.5 N/m.sup.2) at a frequency of about 1 Hz at a
temperature greater than -60.degree. C. In certain methods the
fluid composition may further comprise proppant.
[0014] Another aspect of the disclosure are methods of contacting a
subterranean formation comprising: [0015] injecting into a
well-bore intersecting the subterranean formation a fluid
composition comprising a multicomponent article dispersed in a
carrier fluid wherein the multicomponent article has an aspect
ratio greater than 1:5 (in some embodiments, greater than 1:10,
1:50, 1:100, or even 1:150) and comprises a: [0016] a core having a
softening point of at least 130.degree. C.; and [0017] a sheath
having a softening point up to 130.degree. C.
[0018] Another aspect of the disclosure are methods of contacting a
subterranean formation comprising: [0019] injecting into a
well-bore intersecting the subterranean formation a fluid
composition comprising a multicomponent article dispersed in a
carrier fluid wherein the multicomponent article has an aspect
ratio greater than 1:5 (in some embodiments, greater than 1:10,
1:50, 1:100, or even 1:150) and comprises a: [0020] a core having a
softening point of at least 130.degree. C.; [0021] an outer sheath
that is at least one of (a) inert relative to the carrier fluid or
(b) degradable under the subterranean formation conditions; and
[0022] an intermediate sheath positioned between the core and the
outer sheath, the intermediate sheath having a softening point up
to 130.degree. C.
[0023] Another aspect of the disclosure are methods of contacting a
subterranean formation comprising: [0024] injecting into a
well-bore intersecting the subterranean formation a fluid
composition comprising a first component and a second component
dispersed in a carrier fluid, wherein the first component and the
second component are provided as separate articles to the carrier
fluid separately prior to injection; [0025] forming a network
comprising at least one first component article in direct contact
with another first component article; and [0026] binding the
network with the second component.
[0027] Methods in accordance with an aspect of the disclosure
include methods further comprising modifying at least one of the
first or second components by at least one controlled modification
process. The modification process may be selected from chemical,
physical, mechanical, radiation, and combinations thereof. The
modification process may be selected from temperature activation,
chemical activation, pressure activation, mechanical activation,
curing, exposure to electromagnetic fields, exposure to
electromagnetic radiation, exposure to ionizing radiation, physical
entanglement, degradation, concurrent application of at least two
of these processes, consecutive application of at least two of
these processes, and combinations thereof. Certain methods further
comprise modifying at least one of the first or second components
upon injection into the well-bore. In some embodiments, the method
comprises modifying at least one of the first or the second
components over a period of time after injection into the
well-bore. In other embodiments, the method further comprises
modifying at least one of the first or second components in stages
after injection into the well-bore. In certain embodiments, at
least one of the first component or second component may be an
activated adhesive as described in relation to methods within the
previous aspect of the disclosure. In certain methods, at least one
of the first component or second components may comprise a
degradable polymer. In certain other embodiments, the first
component may be selected from thermoplastic and thermoset
materials. Thermoplastic materials useful in the disclosure as
first components may be selected from polyester, polyamide,
polyolefin, copolymers thereof, and physical mixtures thereof. In
certain embodiments, the second component may be selected from
polyolefins, polyolefin copolymers, polyurethanes, epoxies,
polyesters, polyamides, polyacrylates, and mixtures there of. In
yet other embodiments, the fluid composition may comprise an acid.
At least one of the first or second components may be selected from
polylactic acid and polyglycolic acid. In certain embodiments, the
fluid composition may further comprise proppant.
[0028] Another aspect of the disclosure are methods of contacting a
subterranean formation comprising: [0029] injecting into a
well-bore intersecting the subterranean formation a fluid
composition comprising a first component and a second component
dispersed in a carrier fluid; [0030] forming a network comprising
the first component; and [0031] binding the network with the second
component, [0032] wherein the second component is selected to be
tacky at a specific downhole temperature and have a modulus of less
than 3.times.10.sup.6 dynes/cm.sup.2 (3.times.10.sup.5 N/m.sup.2)
at a frequency of about 1 Hz at a temperature greater than
-60.degree. C.
[0033] Methods in accordance with this aspect of the disclosure
include methods wherein the first component and second component
may be blended together. As used herein "blended together"
includes, but is not limited to, at least the following
embodiments: intermixed; intertwined; adjacent each other;
self-adhered to each other; adhered to each other by a third
component; and mixtures thereof. In certain embodiments, at least a
portion of the first component and a portion of the second
component may be provided in at least one multicomponent article.
In some embodiments, at least one multicomponent article may
comprise the first element, the article having an exterior surface,
and wherein the first element is exposed for at least a portion of
the exterior surface. In certain embodiments, the fluid composition
may further comprise proppant.
[0034] Another aspect of the disclosure are methods of treating a
subterranean formation comprising: [0035] pumping under pressure
into a well-bore intersecting the subterranean formation a fluid
composition comprising a first component and a second component
dispersed in a carrier fluid; [0036] forming a network comprising
the first component; and [0037] binding the network with the second
component, wherein [0038] at least a portion of the first component
and a portion of the second component are provided as
multicomponent articles having an aspect ratio greater than 1:1.1
(in some embodiments, greater than 1:5, 1:10, 1:50, 1:100, or even
1:150).
[0039] Methods in accordance with this aspect of the disclosure may
further comprise contacting a surface of a fracture in the
subterranean formation with the fluid composition, wherein the
fluid composition may further comprise proppant. In certain
embodiments, the fluid composition may comprise a fluid loss
additive. In certain other embodiments, the fluid composition may
comprise acid. In certain other embodiments, the methods further
comprise placing proppant in a fracture in the subterranean
formation. In certain embodiments, the methods may further comprise
modifying at least one of the first or second components by at
least one controlled modification process. In other embodiments,
one of the first component and second component may be an activated
adhesive. In certain embodiments, the second component may be
selected to be tacky at a specific downhole temperature and have a
modulus of less than 3.times.10.sup.6 dynes/cm.sup.2
(3.times.10.sup.5 N/m.sup.2) at a frequency of about 1 Hz at a
temperature greater than -60.degree. C. In yet other methods, at
least some multicomponent articles may comprise the first component
and the second component and other multicomponent articles may
comprise a third component and a fourth component. In yet other
embodiments, one of the first or second component may be the same
as one of the third or fourth components.
[0040] Yet another aspect of the disclosure are methods of reducing
migration of solids comprising: [0041] providing a fluid
composition into a well-bore, the well-bore intersecting a
subterranean formation, the fluid composition comprising a first
component and a second component dispersed in a carrier fluid, at
least one of the first component and second component having an
aspect ratio greater than 1:1.1 (in some embodiments, greater than
1:5, 1:10, 1:50, 1:100, or even 1:150), wherein the second
component is selected to be tacky at a specific downhole
temperature and have a modulus of less than 3.times.10.sup.6
dynes/cm.sup.2 (3.times.10.sup.5 N/m.sup.2) at a frequency of about
1 Hz at a temperature greater than -60.degree. C.; [0042] forming a
network comprising the first component; [0043] binding the network
with the second component; and [0044] contacting the subterranean
formation with the fluid composition.
[0045] Methods in accordance with this aspect of the disclosure
include those methods wherein the forming and binding are performed
prior to contacting. In certain methods the forming and binding may
be performed upon or after contacting. In yet other methods at
least some of the first component may comprise staple fibers,
prolate spheroids, needles, strips, platelets, ribbons, sheets,
tubes, capsules, combinations of more than one of these together in
an article, and mixtures thereof. In certain embodiments, at least
a portion of the first component and a portion of the second
component may be provided in the same multicomponent article. In
other embodiments, at least one multicomponent article may comprise
the first element, the article has an exterior surface, and the
first element may be exposed on at least a portion of the exterior
surface. In certain embodiments, the second component may be an
activated adhesive as described in previous aspects. Certain method
embodiments include those further comprising modifying the second
component after providing into the well-bore; methods further
comprising modifying the second component over a period of time;
and methods further comprising modifying the second component in
stages. In certain embodiments, the solids may comprise formation
fines, and in certain other embodiments the solids may comprise
proppant. In certain embodiments, the second component may be
modified by a process selected from, for example, temperature
activation, chemical activation, pressure activation, mechanical
activation, curing, exposure to electromagnetic fields, exposure to
electromagnetic radiation, exposure to ionizing radiation, physical
entanglement, degradation, concurrently application of at least two
of these processes, consecutive application of at least two of
these processes, and combinations thereof.
[0046] The carrier fluid may be water-based, oil-based, or mixture
thereof, and may or may not comprise one or more gases or vapors
dissolved or dispersed in a liquid, or other common oilfield
additives, such as surfactants, rheology modifiers, and the like.
The carrier fluid may be of any pH, temperature, and pressure, as
long as the first and second components (and optionally other
components, such as proppant particles) are able to be dispersed
therein and are not significantly adversely affected by the pH,
temperature and pressure of the carrier fluid. The network formed
comprises at least a first component (sometimes referred to herein
as a network component) and a second component (sometimes referred
to herein as a modifiable component) designed as stated. The design
includes embodiments wherein the first component is coated (fully
or partially) with the second component; embodiments wherein the
first and second components are intermixed; embodiments wherein the
first and second components are intertwined; embodiments wherein
the first and second components are placed adjacent each other;
embodiments wherein the first and second components are
self-adhered to each other; embodiments wherein the first and
second components are adhered to each other by a third component;
embodiments wherein at least some portions of the network are
multicomponent articles; and mixtures thereof.
[0047] By "multicomponent" is meant having two or more regions of
phase and/or chemical compositions; in other words, two or more
regions that are distinct either physically, chemically, or both
physically and chemically (for example regions having different
glass transition temperatures, Tg). Because multicomponent articles
have at least two distinct regions they may be designed to have
multiple beneficial properties, and these properties may be tuned
to a greater extent than that of a single component material. As
one of many examples, in the case of multicomponent fibers, the
material in the inner core of a core-sheath fiber may be selected
for strength, flexibility and robustness, while the outer layer may
be selected for its adhesive qualities. As another example, a
side-by-side bicomponent fiber may have one component selected for
strength, flexibility and robustness, while the other component may
be selected for its adhesive qualities. Other suitable
multicomponent articles include those wherein the least robust
material is enclosed in a more robust sheath; those wherein
polymers such as PLA and polyglycolic acid is enclosed in a sheath
comprised of polyester, polyamide, and/or polyolefin thermoplastic;
those wherein a sensitive adhesive, for example a
pressure-sensitive adhesive, temperature-sensitive adhesive,
moisture-sensitive adhesive, or curing agent-sensitive adhesive is
enclosed in a degradable sheath, such as a polymer sheath; and
those wherein one of the components is selected to be tacky at a
specific downhole temperature, such as the bottomhole static
temperature (BHST), and have a modulus of less than
3.times.10.sup.6 dynes/cm.sup.2 (3.times.10.sup.5 N/m.sup.2) at a
frequency of about 1 Hz at a temperature greater than -60.degree.
C.
[0048] Certain fluid compositions useful in certain method
embodiments may comprise proppant. Methods within this aspect of
the disclosure include those wherein proppant is combined with the
fluid composition prior to and/or during injecting the fluid
composition into the wellbore. Other methods within the disclosure
include those wherein the injecting comprises pumping the fluid
composition into the wellbore under pressure, either with or
without a proppant in the fluid composition. Exemplary methods of
the disclosure comprise modifying at least a substantial portion of
the modifiable component near a percentage of fractures after
injecting the fluid composition plus proppant into the wellbore,
thereby reducing proppant flowback from that percentage of
fractures. The percentage may range from 10 percent to 100
percent.
[0049] Methods within the disclosure include methods of controlling
(in certain embodiments reducing or eliminating) particle or fluid
flow between the subterranean wellbore and a subterranean
formation. Certain methods of the disclosure are those wherein the
controlling particle flow comprises reducing fines migration from
the subterranean formation into the wellbore. The controlling may
be effected by modifying at least a portion of the modifiable
component.
[0050] In methods of the disclosure the multicomponent articles in
the fluid compositions may all be the same, or mixtures of two or
more different multicomponent articles. For example, the modifiable
component may be the same or different from one multicomponent
article to the other in the same fluid composition. Furthermore,
the network component may be the same or different from one
multicomponent article to the other in the same fluid composition.
Alternatively, methods of the disclosure may comprise injecting a
first fluid composition within the disclosure, followed
sequentially by one or more additional fluid compositions within
the disclosure, each fluid composition within the disclosure having
a different network component, or a different modifiable component,
or both.
[0051] Oilfield operations within the disclosure include completion
operations, acidizing, fracturing, flow diverting and other
operations. The environmental conditions of the wellbore during
running and retrieving may be the same or different from the
environmental conditions during use in the wellbore or at the
surface. Methods of the disclosure include those comprising using a
first fluid composition of the disclosure downhole to perform a
first task, a second fluid composition of the disclosure to perform
a second task downhole, and so on.
[0052] The various aspects of the disclosure will become more
apparent upon review of the brief description of the drawings, the
detailed description of the disclosure, and the claims that
follow.
BRIEF DESCRIPTION OF THE DRAWINGS
[0053] The manner in which the objectives of the disclosure and
other desirable characteristics can be obtained is explained in the
following description and attached drawings in which:
[0054] FIGS. 1A-1D are schematic cross-sections of four prior art
multicomponent fibers useful in methods of the disclosure;
[0055] FIGS. 2A-2G are schematic perspective views of various
multicomponent articles useful in methods of the disclosure;
[0056] FIG. 3 is a schematic plot of modulus (dynes/cm.sup.2) vs.
temperature (.degree. C.) comparing measurable bond strength to
parallel plates of two different multicomponent fibers useful in
the disclosure, illustrating that these fibers had measurable bond
strength and in addition satisfied the Dahlquist criteria for tack;
and
[0057] FIG. 4 is a plot of fiber concentration versus proppant pack
flow during flowback tests.
DETAILED DESCRIPTION
[0058] In the following description, numerous details are set forth
to provide an understanding of the present disclosure. However, it
will be understood by those skilled in the art that the present
disclosure may be practiced without these details and that numerous
variations or modifications from the described embodiments may be
possible.
[0059] Described herein are methods of using fluid compositions
comprising one or more multicomponent articles or materials for
downhole well servicing. Also described are networks made from the
fluid compositions after the fluid compositions are pumped downhole
and exposed to one or more modifying conditions. As used herein the
term "oilfield" includes land based (surface and sub-surface) and
sub-seabed applications, and in certain instances seawater
applications, such as when exploration, drilling, or production
equipment is deployed through a water column. The term "oilfield"
as used herein includes oil and gas reservoirs, and formations or
portions of formations where oil and gas are expected but may
ultimately only contain water, brine, or some other
composition.
[0060] It should be understood that methods of the disclosure may
be conducted under one or more conditions of high pressure, high
temperature, high shear, and high corrosion. "Well operation" as
used herein includes, but is not limited to, well stimulation
operations, such as hydraulic fracturing, acidizing, acid
fracturing, fracture acidizing, fluid diversion, sand control
gravel packing, gravel pack improvement, particulate migration
reduction, completion operations using completion tools and/or
completion tool accessories, or any other well treatment, whether
or not performed to restore or enhance the productivity of a
well.
[0061] Solids migration can be a significant issue in subterranean
well construction, intervention and stimulation operations. These
solids, usually of a granular nature, can be composed of many
different materials of many different sizes. They may be the actual
proppant pumped during a fracturing treatment, or the finer grained
material produced by the crushing of these proppants. They may also
be grains or fines spalled or eroded from the subterranean rock
surface. They may be composed of salts or scale precipitates. In
some cases they can be of an organic nature, such as asphaltene,
lignitic, Kerogenic, and anthracitic in nature. They may also be
introduced into the formation. For example they may be finely
ground sand, mica, or other mineral materials used as fluid loss
agents.
[0062] In many situations it is desirable that these granular
materials are immobilized and prevented from migrating. For
example, after many hydraulic fracture treatments are completed it
is a common occurrence that some of the proppant can flow back.
This reduces the overall effectiveness of the treatment, and the
flowing proppant can cause damage to the subterranean and/or
surface equipment.
[0063] In other situations, it is desirable that formation fines
are prevented or reduced from migrating to the degree possible.
Fines production is a common occurrence in many weak formations
including that of coal seams. Although it is practically
unavoidable that some fines are produced, they cause the greatest
damage when large quantities of these fines are generated and are
allowed to migrate and clog up the pores of the hydraulic fracture.
In some situations it may be much better if these fines were
localized close to their place of origin, and were not allowed to
migrate and accumulate.
[0064] Another example where solids immobilization is useful is for
the creation and placement of "filtercakes" and fluid leakoff
additives. Often materials are added to wellbore construction,
intervention and stimulation processes with the express intent of
blocking or impeding fluid flow across a rock surface. These
materials include but are not limited to finely ground sand, finely
ground limestone, spun limestone, rock wool, sized calcium and
magnesium carbonate particles, benzoic acid flakes, and the like.
It is best if the materials added stay in place, first so that less
material is used, and second so that migration of this material
does not cause damage somewhere else in the fracture or
wellbore.
[0065] In the following discussion, while the focus is on
multicomponent fibers, it will be appreciated by those of skill in
the art that the discussion is equally applicable to other
multicomponent articles of the disclosure having aspect ratio
greater than 1:1.1 (in some embodiments, greater than 1:5, 1:10,
1:50, 1:100 or even 1:150), including prolate spheroids, needles,
strips, platelets, ribbons, sheets, capsules, pellets, and the
like, and mixtures thereof, which may have any number of shapes
viewed in perspective view, such as prismatic, cylindrical, lobed,
rectangular, faceted, and the like. Some of these other shapes are
illustrated in FIG. 2, discussed further herein.
[0066] One useful set of multicomponent articles are multicomponent
core-sheath fibers having (or which may be modified to have) a
tacky external sheath. These fibers are comprised of two or more
materials. In an example of a two component fiber one material
supplies a flexible to rigid network under the well conditions,
while the second material serves to adhere to other fibers,
proppant, rock and/or other interfaces in the well. The fiber
components are chosen to achieve performance in the specific well
conditions, and this is what is meant by "designed" herein. Having
the second material allows the formation of "netting" or a network
of first component connected by portions of the second material
produced in-situ downhole such that oil, gas or other fluids may
pass through but particulate matter will not. The flexible
"backbone" of the fibers helps the reinforced proppant pack
withstand stress cycling. Also as a result of the tacky component
debris that might otherwise pass through the "netting" will become
adhered to the fibers.
[0067] Four examples of multicomponent fibers useful in the methods
and systems of the disclosure are illustrated in FIGS. 1A-D. For
example, embodiment 10 of FIG. 1A comprises a pie-wedge fiber
having a circular cross-section 12, and a first component 14a and
14b, a second component 16a and 16b, and a third component 18a and
18b. FIG. 1B illustrates a fiber 20 having a circular cross-section
22 that may have two or more components: a single component sheath
24, and one or more other components in more interior fibers 26.
FIG. 1C illustrates an embodiment 30 also having a circular
cross-section 32, with four layered regions 34a, 34b, 36a, and 36b,
which may comprise two, three, or four different compositions,
phases, and the like. FIG. 1D illustrates another bi-component
fiber embodiment 40 having a core-sheath structure (also sometimes
referred to as sheath-core structure; the terms are considered
equivalent structures and structural equivalents herein) having a
sheath 44 and a core 46.
[0068] Multicomponent articles useful in the disclosure are not
limited to fibers. FIGS. 2A-G illustrate perspective views of other
structures. FIG. 2A illustrates an article 50 having a triangular
cross-section 52, wherein a first component 54 exists in one
region, and a second component 56 is positioned adjacent first
component 54, and where one of components 54 and 56 is modifiable.
FIG. 2B illustrates an embodiment 60 having an outer capsule or
pellet shape 62. Embodiment 60 comprises a core region 64 having a
first composition, and an outer region 68 comprising a second
composition surrounding core 64. Optionally, a coating 66 may
comprise a third composition. At least one of components 64, 66 and
68 is modifiable. FIG. 2C illustrates a ribbon-shaped embodiment 70
having a generally rectangular cross-section and an undulating
shape 72. A first layer 74 comprises a first composition, while a
second layer 76 comprises a second composition, where one of
components 72 and 74 is modifiable. FIG. 2D illustrates a coiled or
crimped fiber embodiment 80 having a first component 82 along side
a second component 84, where one of components 82 and 84 is
modifiable. The distance between coils, 86, may be adjusted
according to the properties desired. FIG. 2E illustrates a platelet
embodiment 90 of irregular shape having a first layer 92, a second
layer 94, and a third layer 96 each having different compositions,
where at least one of components 92 and 94 is modifiable. In some
embodiments, the first or second component may be non-polymeric and
the third layer being an inert material such as finely divided
calcium carbonate, mica, or fatty acids. In such embodiments, the
third layer may serve as a barrier to adhesion until conditions
(such as squeezing or pinching of the fiber between grains of
proppant) occur to alter its integrity.
[0069] It should be noted that each component need not have the
same shape, length, width or thickness. FIG. 2F illustrates an
embodiment 100 having a cylindrical shape, and having a first
annular component 102, a second annular component 104, the latter
component defining hollow core 106. Hollow core may optionally be
partially or fully filled with an additive, such as a tackifier,
curing agent or the like for one of the components 102, 104, where
at least one of components 102 and 104 is modifiable. FIG. 2G
illustrates a lobed-structure 110 having five lobes 112. A first
component 114 exists in the outer portions of lobes 112, while a
second component 116 fills the remainder of the structure. At least
one of components 114 and 116 is modifiable. These are merely
representative examples of multicomponent articles useful in the
disclosure, and are not intended to be limiting in any way. Methods
of making these structures, as well as more complicated structures,
are considered well-known to the skilled artisan.
[0070] In some multicomponent articles useful in the disclosure,
one component or region of the article may be tacky, or is designed
to have latent tackiness (in other words tack can be increased by
exposure to one or more conditions during or after deployment
through a wellbore). The tack properties of articles useful in the
disclosure may be controlled by at least two methods, which may be
used individually or in combination. The first method is
temperature activation of the polymer comprising an external sheath
as it warms up in the wellbore or in the fracture. Certain
embodiments may be activated at or near the bottomhole static
temperature (BHST). A number of the multicomponent fibers are known
which have been developed as binders for the nonwoven fabrics
business. Some examples include: a) a segmented fiber comprised of
about 70 percent high density polyethylene/30 percent polyethylene
terephthalate; and b) a core-sheath fiber composed of two polyester
resins, marketed under the trade designation "KOSA T-259", by KoSa,
Salisbury, N.C.
[0071] Tack is defined as the property of a material that enables
it to form a bond of measurable strength after it is brought into
contact under pressure with another material. Tack is deemed a
desirable property of fibers and other multicomponent articles
useful in the disclosure, and in situ networks useful in the
disclosure, for solids migration control, as it is thought to
create a bond between solids, for example proppant, fines,
precipitates, and the like, and the walls of the fractured
borehole. Using a stress-controlled rheometer (model AR2000
manufactured by TA Instruments, New Castle, Del.), a test method
was developed to measure the bond strength of various fibers as a
function of temperature. The results are illustrated in FIG. 3 for
the two fibers mentioned previously. Results for the 70 percent
high density polyethylene/30 percent polyethylene terephthalate
fibers are represented by the solid line in FIG. 3, while results
for the a core-sheath fiber composed of two polyester resins,
marketed under the trade designation "KOSA T-259" are represented
by the dashed line in FIG. 3. In the test, a plurality of fibers
were placed between two 20 mm parallel plates of a rheometer and a
sinusoidal frequency of 1 Hz at 1% strain applied over a
temperature range of 100-150.degree. C. Results are shown in FIG. 3
plotted as modulus (dynes/cm.sup.2) vs. temperature (.degree. C.).
The two samples had measurable bond strength and in addition
satisfied the Dahlquist criterion for tack. This criterion
stipulates that at a given temperature the modulus of any tacky
adhesive is less than 3.times.10.sup.6 dynes/cm.sup.2
(3.times.10.sup.5 N/m.sup.2) at a frequency of about 1 Hz.
[0072] Methods and systems for applying heat to a region of a
wellbore are known and described for example in U.S. Pat. No.
6,023,554 (George et al.) and in Published US Patent Application
Publication Number 2005/0269090 (Vinegar et al.), each of which are
incorporated herein by reference. Heated fluids useful in the
disclosure that function to deliver heat to regions of a formation
may be selected from gases, vapors, liquids, and combinations
thereof, and may be selected from water, organic chemicals,
inorganic chemicals, steam, and mixtures thereof.
[0073] A second method is chemical activation. In these embodiments
a solvent or tackifying agent is added to the fluid to soften and
tackify one of the polymers comprising the fiber or other article.
This may be performed in combination with temperature activation.
The solvent may be combined with other components of fluid
compositions useful in methods of the disclosure, or pumped in
separately as a slug. Another method is stress or contact pressure
activation of adhesion, for example by the pinching of fiber
between adjacent grains of proppant, or between grains of proppant
and the wall of the fracture.
[0074] Tackifiers typically comprise an organic material having a
glass transition temperature of no less than about 120.degree. C.
(in certain embodiments, no less than about 150.degree. C.) and a
diluent present in sufficient amount to give the tackifier a
kinematic viscosity ranging from about 3,000 to about 5,000
centistokes at 100.degree. C. The diluent may be an organic oil,
such as a mineral oil (i.e., a hydrocarbon oil derived from
petroleum, such as paraffin oils, naphthenic oils, and the like, or
a coal oil or rock oil). One particularly useful mineral oil is
slate oil. Another particularly useful mineral oil is seneca oil.
These oils will generally have a kinematic viscosity ranging from
about 100 to about 300 centistokes at 100.degree. C., and some will
have a kinematic viscosity ranging from about 150 to about 250
centistokes. As used herein "kinematic viscosity" has its generally
accepted meaning, the absolute viscosity (sometimes referred to as
the dynamic viscosity) of the fluid divided by its mass density. In
certain embodiments, the diluent may comprise one or more
light-colored naphthenic oils. The amount of tackifier present in a
multicomponent article useful in practicing the disclosed methods
preferably ranges from about 0.5 to about 2 weight percent, or from
about 0.5 to about 1 weight percent of the total weight of a
multicomponent article. An adhesion agent may also be present, the
amount of adhesion agent ranging from about 0.5 to about 5 weight
percent of the multicomponent article weight, the balance being
organic oil. The organic material component of tackifiers useful in
the disclosure may be selected from organic monomers, oligomers or
polymers having a glass transition temperature (Tg) no less than
about 120.degree. C., in some embodiments, no less than about
150.degree. C. Two categories of organic polymeric materials useful
in tackifier compositions are polyalkylene resins and
polycycloalkene resins, the latter group including aromatic organic
resins. Useful polyalkylene resins include polybutene resins,
dipentene resins, terpolymers of ethene, 1-propene, and
1,4-hexadiene, and the like. Useful polycycloalkene resins include
phenol-aldehyde resins; polyterpene resins; rosins, including rosin
acids and esters, and hydrogenated rosins; polyethylene rosin
esters; phenolic polyterpene resins; limonene resins; pinene resins
such as alpha and beta pinene resins; styrenated terpene resins,
and the like. An example of a tackifier useful in compositions
methods of the disclosure comprises a terpolymer of ethene,
1-propene, and 1,4-hexadiene adjusted to the above preferred
kinematic viscosity with a light-colored naphthenic oil, such as
the naphthenic oil known under the trade designation "HS-500",
available from Cross Oil & Refining Co., Smackover, Ariz. Other
suitable tackifiers and their ingredients are discussed in U.S.
Pat. No. 5,362,566 (George et al.), incorporated herein by
reference.
[0075] A second set of useful multicomponent articles are
multicomponent fibers having an outer protective sheath. Many of
the low cost polymers that would be useful for subterranean
application are of the type known as condensation polymers.
Polyamides and polyesters are two examples. These materials often
have suitable mechanical properties for proppant flowback control
but are prone to hydrolytic degradation (either main polymer chain
degradation, side chain degradation, or both) in subterranean
environments. Furthermore, many of their degradation products can
precipitate out with divalent cations in the formation or in the
production line causing damage or a reduction in productivity.
Phenol-formaldehyde and melamine-based resins on the other hand,
although more impervious to chemical degradation, have less
desirable mechanical properties and are more difficult to fabricate
and handle in the fibrous form.
[0076] In these versions of useful multicomponent articles, the
multicomponent articles comprise an inner material coated with a
second composition, for example the inner material being relatively
more prone to hydrolysis than the outer material. In one
embodiment, the articles may be multicomponent coated fibers, which
are particularly useful for reducing solids migration--in
particular for proppant flowback control. The inner material may be
selected for its mechanical properties, its cost and its ease of
fabrication. The outer, coating material may be selected for its
ability to withstand hydrolytic degradation. Two examples are
given. A first example, which may have structure such as
illustrated in FIG. 1D, is a polylactic acid fiber as core 46 of a
multicomponent fiber, co-extruded with a polyamide or PET shell as
sheath 44. A second example may be a polyamide core covered by a
phenolic or melamine based resin system.
[0077] Another set of multicomponent articles that may be useful in
practice of methods of this disclosure are multicomponent fibers
comprising at least one curable component. These embodiments are
similar to embodiments described herein comprising core-sheath
fibers having (or which may be modified to have) a tacky external
sheath, however in embodiments comprising a curable component,
during the time that a fluid composition of the disclosure is
pumped into a wellbore, the outer surface of the fibers or other
articles are in an uncured state, or in a partially cured state, or
contain components that may initiate curing through action of a
latent curing agent. An example is a coating comprising an uncured
epoxy resin having dispersed therein a latent, heat activated
curing agent. The advantage is similar to the embodiments employing
tacky materials but the surface bonds to the proppant grains, to
other fibers, or the wall of the fracture would be stronger and
more permanent. The underlying fiber gives flexibility to the
bonded structure that would help the proppant pack withstand stress
cycling.
[0078] Another set of multicomponent articles that may be useful in
the practice of the disclosure are multicomponent articles
comprising at least one degradable component. As used herein
degradable may mean degradable by physical, chemical (including
pH), mechanical, radiation means, and combinations thereof. In some
applications it would be advantageous for one or more of the
article components to be degradable or soluble in the subterranean
environment. Polylactic acid (PLA) is an example of a polymer that
is degradable and soluble in downhole conditions. Polyvinyl alcohol
may be extruded into soluble fibers. One example where this would
be advantageous would be that very tacky strips of polyvinyl
alcohol could be covered in PLA to facilitate handling, well site
delivery and mixing. In this way thin strips or films of very
highly tacky or curable resin with high surface area to volume
ratios could be placed into the fracture or on surfaces within the
wellbore or bottom hole assembly. The soluble PLA minimizes the
total volume of material left in the pore space, thereby minimizing
hydraulic conductivity damage.
[0079] The degradable component functions to dissolve when exposed
to the wellbore conditions in a user controlled fashion, i.e., at a
rate and location controlled by the structure of the first
component. In this way, zones in a wellbore, or the wellbore itself
or branches of the wellbore, may be blocked for periods of time
uniquely defined by the user. The degradable second component may
comprise a degradable inorganic material, a degradable organic
material, and combinations thereof. Degradable water-soluble
organic materials may comprise a water-soluble polymeric material,
for example, poly(vinyl alcohol), poly(lactic acid), and the like.
The water-soluble polymeric material may either be a normally
water-insoluble polymer that is made soluble by hydrolysis of side
chains, or the main polymeric chain may be hydrolysable.
[0080] Certain fluid compositions useful in the disclosure may
comprise multicomponent articles comprised of a thermoplastic
materials covered by a fully cured or partially cured thermosetting
material. In embodiments wherein the thermosetting material is only
partially cured while the fluid is being pumped downhole, the
thermosetting materials may be fully cured by bottomhole
conditions.
[0081] Fluid compositions and multicomponent articles useful in the
disclosure may comprise metallic fibers or nonmetallic fibers
coated with a thermosetting material. Suitable nonmetallic fibers
include glass fibers, carbon fibers, mineral fibers, synthetic or
natural fibers formed of heat resistant organic materials, or
fibers made from ceramic materials. The metallic and nonmetallic
fibers may be "hydrocarbon resistant" organic fibers, meaning they
are resistant to, or resistant to breaking down, under the wellbore
conditions. Examples of useful natural organic fibers include wool,
silk, cotton, or cellulose. Examples of useful synthetic organic
fibers include polyvinyl alcohol fibers, polyester fibers, rayon
fibers, polyamide fibers, acrylic fibers, aramid fibers, and
phenolic fibers. Generally, any ceramic (i.e., glass, crystalline
ceramic, glass-ceramic, and combinations thereof) fiber is useful
in applications of the present disclosure. An example of a ceramic
fiber suitable for the present disclosure is available from the 3M
Company, St. Paul, Minn. under the trade designation "NEXTEL".
Glass fibers may be used, at least because they impart desirable
characteristics to the articles and are relatively inexpensive.
Furthermore, suitable interfacial binding agents exist to enhance
adhesion of glass fibers to thermoplastic materials, such as a
silane coupling agent, to improve the adhesion to the thermoplastic
material. Examples of silane coupling agents include those
available under the trade designations "Z-6020" and "Z-6040," from
Dow Corning Corp., Midland, Mich.
[0082] Other suitable multicomponent articles include those wherein
the least robust material is enclosed in a more robust sheath;
those wherein polymers such as PLA and polyglycolic acid is
enclosed in a sheath comprised of polyester, polyamide, and/or
polyolefin thermoplastic; those wherein a sensitive adhesive, for
example a pressure-sensitive adhesive, temperature-sensitive
adhesive, moisture-sensitive adhesive, or curable adhesive is
enclosed in a degradable polymer sheath; and those wherein one of
the components is selected to be tacky at a specific downhole
temperature, such as the bottomhole static temperature (BHST), and
have a modulus of less than 3.times.10.sup.6 dynes/cm.sup.2
(3.times.10.sup.5 N/m.sup.2) at a frequency of about 1 Hz at a
temperature greater than -60.degree. C., the tacky component
embedded in a degradable polymer sheath. Sensitive adhesives such
as pressure-sensitive adhesives, temperature-sensitive adhesives,
and moisture-sensitive adhesive, as well as curable adhesives, are
well-known to those in the adhesives and fibers arts, and require
no further explanation herein.
[0083] Suitable multicomponent articles are also described, for
example, in U.S. Provisional Patent Application having Ser. No.
61/014,004 (Attorney Docket No. 63584US002; entitled
"Multi-Component Fibers"), filed the same date as the instant
application, the disclosure of which is incorporated herein by
reference.
[0084] Under some circumstances it may be advantageous to deploy
downhole pre-fabricated woven or non-woven assemblies, for example,
mats, from materials such as those described herein comprising a
first (network) component and second (modifiable) component. In
general, the size of these assemblies is limited only by the
practicalities of deploying the materials downhole. One deployment
method may entail pumping a fluid composition comprising one or
more prefabricated assemblies. Another deployment method may entail
attaching the assembly to the end or near the end of a tubing, such
as coiled tubing, running the tubing into the wellbore, and placing
the assembly at a desired location.
Example
[0085] A testing apparatus comprising the following assemblies was
used: a flowback cell for containing the proppant pack being
testing; a circulation system for pumping fluid through the
proppant pack in the cell; and a hydraulic press to apply a
uniaxial closure stress onto the proppant pack. The flowback cell
consisted of a rectangular body that had an interior 5.25
in.times.5.25 in (13.3 cm.times.13.3 cm) working area which held
the proppant pack. After the cell was filled with the proppant
pack, a square piston was inserted into the body on top of the
proppant pack. Water was pumped through the rectangular proppant
pack from an upstream inlet side through to the discharge side. On
the upstream side of the cell, there were three 13 mm inlets for
the inflow of water. On the discharge side of the cell there was a
10 mm outlet that represents a perforation. In this configuration,
the proppant pack was free to move if it had insufficient strength
to withstand the stresses generated by the flow of water. After the
flowback cell was filled and assembled, it was placed in the
hydraulic press which then applied a designated closure stress to
the proppant pack. The test apparatus was computer controlled, and
data acquired included measurements of pack width, flow rate and
upstream pressure.
[0086] The proppant flowback stability measurements were performed
on a sand pack made from a fracturing sand of 20/40 mesh (API RP
56) obtained from Badger Mining Corporation, Berlin, Wis., and the
flowback control additives. The total mass of the solids in the
pack (sand plus flowback control additives) was set at 400 grams.
The uniaxial closure stress was set to 4000 psi (27.6 MPa), and the
tests were performed at 90.degree. C. At the start of each test the
flow rate of water was zero. As the test progressed the flow rate
of water was continuously increased at a rate of 4 L/min. till pack
failure was observed. The flow rate at the pack failure was used as
a characteristic of the flowback stability of the proppant
pack.
[0087] Fibers were added to the proppant pack and tested for
flowback. A single component nylon fiber, having a length of 17 mm
long and a diameter of 6 mm and a bicomponent polyamide/ionomeric
fiber having length of 17 mm and diameter of 6 micrometers were
tested. The single component fiber was provided by 3M Company, St.
Paul Minn., while the bicomponent fiber was a nylon core with
SURLYN.TM. (mark of DuPont Corporation) sheath provided by 3M
Company, St. Paul, Minn. In order to compare the different fibers,
test results were normalized according to the linear concentration
of fibers in meters per gram of proppant in the test cell. FIG. 4
shows the test results where the flow rate at pack failure is
plotted against the linear fiber concentration in the pack. Pure
sand started flowing at rates as low as 0.5 L/min. under these
conditions. The results showed that the bicomponent fibers
significantly improved pack strength even at lower fiber
concentration. With 18-22.5 meters of single component fiber per
gram of proppant, the packs begin to fail at flow rates of 2.9-3.9
L/min. With the bicomponent fibers, it was possible to increase the
up to 4.9 L/min. at half the linear fiber concentrations (9
m/gram). When 18 m/gram bicomponent fiber was used, the flow rate
was 5.7 L/min. at failure.
[0088] Multicomponent articles and fluid compositions comprising
same may be employed in methods of the disclosure for solids and/or
fluid control in reservoirs. Multicomponent articles such as
multicomponent fibers comprising a tacky and/or curable adhesive
surface may include porous proppants impregnated with a tackifying
substance or curing agent for controlled release. When used for
solids mobility control (for example, proppant flowback control,
and/or fines migration control) the solids adhere to the surface of
the fibrous material. The fiber may comprise a part of a
homogeneous fiber-proppant network (pumped during proppant stage)
or the fibers or other articles may be used without proppant as
networks in or part of a filter-cake, or pumped downhole during the
pad stage. The networks may be temporary in nature by releasing a
tacky or curable coating upon dissolution covering the proppant
pack, or the fiber or other article may be partially soluble by
coating the surrounding proppant while maintaining the integrity of
the fibrous network.
[0089] While the bulk of this discussion has been about proppant
flowback control, methods of the disclosure relate to any method or
process of treating an underground formation penetrated by a
wellbore comprising designing a fluid composition of the
disclosure; pumping or otherwise deploying the fluid composition
downhole through a wellbore; depositing the fluid composition in
the formation; and forming within the formation a 2- or
3-dimensional network comprising the first and second components.
This may include fracturing methods; methods wherein the designing
of the fluid composition comprises designing a gravel pack fluid
composition, pumping the gravel pack fluid composition downhole
through a wellbore, depositing a gravel pack fluid; methods
comprising designing a fluid composition able to increase
competency of a granular pack in a wellbore, comprising providing a
fluid composition of the disclosure to the pack, and modifying the
modifiable component. Methods within this aspect include those
wherein the pack comprises materials selected from proppant
previously placed in fractures in a subterranean formation, sand in
the subterranean formation, a gravel pack, and combinations
thereof.
[0090] Other methods of the disclosure comprise preparing and/or
pretreating the surface of a fracture. That is, the fluid
composition is deployed early in the treatment prior to the
addition of proppant.
[0091] In other methods of the disclosure, a fluid composition may
be deployed in combination with one or more conventional fluid loss
additives (for example fine sand or the like) for application to
the surface of the fracture or the surface of the wellbore.
[0092] Further methods of the disclosure include deploying a
composition of the disclosure in combination with single component
elongated elements, for example single component fibers (wherein
the modifiable component of the multicomponent articles functions
as a binder for conventional fibrous materials within a proppant
pack, fiber plug, or the like).
[0093] Further methods of the disclosure include deploying two
different compositions of the elongated articles intermingled in
the fluid, with or without proppant. Once these articles are place
in the formation they can act synergistically to create a network
structure. For example one of the multicomponent fibers could
contain an epoxy resin and the second could contain a curing agent.
Alternatively, for example, one of the multicomponent fibers could
contain a temperature activated melt-bondable adhesive material
that acts over a period of time and another multicomponent fiber
could contain an epoxy adhesive that acts over a different period
of time.
[0094] In other methods of the disclosure, a fluid composition may
be deployed in acid fracturing applications, and fracture acidizing
applications. Acidizing means the pumping of acid into the wellbore
to remove near-well formation damage and other damaging substances.
Acidizing commonly enhances production by increasing the effective
well radius. When performed at pressures above the pressure
required to fracture the formation, the procedure is often referred
to as acid fracturing. Fracture acidizing is a procedure for
production enhancement in which acid, usually hydrochloric (HCl),
is injected into a carbonate formation at a pressure above the
formation-fracturing pressure. Flowing acid tends to etch the
fracture faces in a nonuniform pattern, forming conductive channels
that remain open without a propping agent after the fracture
closes. The length of the etched fracture limits the effectiveness
of an acid-fracture treatment. The fracture length depends on acid
leakoff and acid spending. If acid fluid-loss characteristics are
poor, excessive leakoff will terminate fracture extension.
Similarly, if the acid spends too rapidly, the etched portion of
the fracture will be too short. The major problem in fracture
acidizing is the development of wormholes in the fracture face;
these wormholes increase the reactive surface area and cause
excessive leakoff and rapid spending of the acid. To some extent,
this problem can be overcome by using inert fluid-loss additives to
bridge wormholes or by using viscosified acids. Fracture acidizing
is also called acid fracturing or acid-fracture treatment.
Compositions of the disclosure may be used in these applications,
as the acidic solution may decompose the composition selectively
rather than other components or geologic formations.
[0095] Traditional (single component) fibers or other single
component shaped particles may be used, in conjunction with the
fluid compositions, multicomponent articles, and methods of the
disclosure, to strengthen, reinforce, or bind filter cakes and
fluid leakoff additives in the wellbore, in downhole networks of
the disclosure, or in the fracture itself. What follows is a brief
discussion of single-component staple fibers and their
properties.
[0096] Single-component staple fibers may comprise crimped or
non-crimped thermoplastic organic fibers comprising polyamide and
polyester fibers, although it is also known to use other fibers
such as rayon.
[0097] Melt-bondable fibers may be used to help stabilize the
networks in the wellbore and may facilitate trapping particulate
materials. Melt-bondable fibers useful in the present disclosure
may be made of polypropylene or other low-melting polymers such as
polyesters as long as the temperature at which the melt-bondable
fibers melt and thus adhere to the other fibers in the network
construction is lower than the temperature at which the staple
fibers or melt-bondable fibers degrade in physical properties under
wellbore conditions. Suitable and preferable melt-bondable fibers
include those described in U.S. Pat. No. 5,082,720 (Hayes),
incorporated herein by reference. Melt-bondable fibers suitable for
use in this disclosure must be activatable at elevated temperatures
below temperatures which would adversely affect other ingredients.
Typically, melt-bondable fibers have a concentric core and a
sheath. Alternatively, melt-bondable fibers may be of a
side-by-side construction or of eccentric core and sheath
construction.
[0098] The length of the organic fibers employed is primarily
dependent on upon the limitations of the pumping equipment.
However, depending on types of equipment, fibers of different
lengths, or combinations thereof, very likely can be utilized in
forming the networks downhole having the desired ultimate
characteristics specified herein. For pumping applications the best
fiber length is below 20 mm, in certain embodiments, less than 19
mm, in certain other embodiments, less than 12 mm, and in other
embodiments, around 6 mm.
[0099] Fluid compositions may be pumped into the well from the
surface using any of a number of pumping systems which are not a
part of the disclosure per se.
[0100] The fluid portion of fluid compositions useful in the
disclosure that does not form a network downhole comprises fluid
that must be returned to the surface. In many formations this may
be accomplished naturally due to the residual pressure after the
fracturing treatment is completed, or due to high reservoir
pressure. This may be accomplished artificially using a downhole
pump. One option is to use an electrical submersible pump ("ESP"),
such as pumping systems known under the trade designation AXIA.TM.,
from Schlumberger Technology Corporation, Sugar Land, Tex.
[0101] When desired, proppant may be pumped into the formation,
either combined with the compositions of the disclosure, or
combined in situ. As has been indicated above, the function of a
proppant is to "prop" the walls adjacent a fracture in a
subterranean formation apart so that the fracture is not closed by
the forces which are extent in the formation. It is advantageous
for the walls adjacent the fracture to be "propped" apart so that
the formation can be worked, usually to remove oil or natural gas.
In general the fluid compositions, multicomponent articles therein,
methods, and networks of the disclosure perform well with any known
proppant, but may be particularly effective when using the least
expensive proppant, siliceous sand. At greater stresses, it is
believed, the sand particles are disintegrated, forming fines which
then may plug the formation, reducing its permeability and
resulting in costly well cleanouts, or even abandoning the well.
This is discussed in U.S. Pat. No. 3,929,191 (Graham et al.), the
disclosure of which is incorporated herein by reference. Sintered
bauxite has also been used as a proppant, and may be preferable to
siliceous sand because of its ability to withstand higher stresses
without disintegration. However, sintered bauxite can be less
desirable than siliceous sand as a proppant because it is
substantially more expensive and is less generally available. The
use of sintered bauxite as a proppant is disclosed in U.S. Pat. No.
4,068,718 (Cooke et al.), the disclosure of which is incorporated
herein by reference.
[0102] Other suitable proppants are described, for example, in U.S.
Pat. No. 6,406,789 (McDaniel et al.); U.S. Pat. No. 6,582,819
(McDaniel et al.); and U.S. Pat. No. 6,632,527 (McDaniel et al.),
the disclosures of which are incorporated herein by reference. As
the '789 patent explains, three different types of propping
materials (i.e., proppants) are currently employed. The first type
of proppant is a sintered ceramic granulation/particle, usually
aluminum oxide, silica, or bauxite, often with clay-like binders or
with incorporated hard substances such as silicon carbide (e.g.,
U.S. Pat. No. 4,977,116 (Rumpf et al.), incorporated herein by
reference, EP Patents 0 087 852, granted Apr. 2, 1986, 0 102 761,
published Mar. 14, 1984, or 0 207 668, granted Apr. 5, 1984). The
ceramic particles have the disadvantage that the sintering must be
done at high temperatures, resulting in high energy costs. The
second type of proppant is made up of a large group of known
propping materials from natural, relatively coarse, sands, the
particles of which are roughly spherical, such that they can allow
significant flow (English "frac sand") (see U.S. Pat. No. 5,188,175
(Sweet) for the state of the technology). The third type of
proppant includes samples of type one and two that may be coated
with a layer of synthetic resin (U.S. Pat. No. 5,420,174
(Deprawshad et al); U.S. Pat. No. 5,218,038 (Johnson et al.); and
U.S. Pat. No. 5,639,806 (Johnson et al.) (the disclosures of U.S.
Pat. No. 5,420,174 (Deprawshad et al), U.S. Pat. No. 5,218,038
(Johnson et al.) and U.S. Pat. No. 5,639,806 (Johnson et al.), are
incorporated herein by reference); and EP Patent No. 0 542 397,
published May 19, 1993). As discussed herein, in some hydraulic
fracturing circumstances, the precured proppants in the well would
flow back from the fracture, especially during clean up or
production in oil and gas wells. Some of the proppant can be
transported out of the fractured zones and into the well bore by
fluids produced from the well. This transportation is known as flow
back. Flowing back of proppant from the fracture is undesirable and
has been controlled to an extent in some instances by the use of a
proppant coated with a curable resin which will consolidate and
cure underground. Phenolic resin coated proppants have been
commercially available for some time and used for this purpose.
Thus, resin-coated curable proppants may be employed to "cap" the
fractures to prevent such flow back. The resin coating of the
curable proppants is not significantly crosslinked or cured before
injection into the oil or gas well. Rather, the coating is designed
to crosslink under the stress and temperature conditions existing
in the well formation. This causes the proppant particles to bond
together forming a 3-dimensional matrix and preventing proppant
flow back. These curable phenolic resin coated proppants work best
in environments where temperatures are sufficiently high to
consolidate and cure the phenolic resins. However, conditions of
geological formations vary greatly. In some gas/oil wells, high
temperature (>180.degree. F. (82.degree. C.)) and high pressure
(>6,000 psi (41 MPa)) are present downhole. Under these
conditions, most curable proppants can be effectively cured.
Moreover, proppants used in these wells need to be thermally and
physically stable (i.e., do not crush appreciably at these
temperatures and pressures). Curable resins include (i) resins
which are cured entirely in the subterranean formation and (ii)
resins which are partially cured prior to injection into the
subterranean formation with the remainder of curing occurring in
the subterranean formation. Many shallow wells often have downhole
temperatures less than 130.degree. F. (54.degree. C.), or even less
than 100.degree. F. (38 .degree. C.).
[0103] Due to the diverse variations in geological characteristics
of different oil and gas wells, no single proppant possesses all
properties which can satisfy all operating requirements under
various conditions. The choice of whether to use a precured or
curable proppant or both is a matter of experience and knowledge as
would be known to one skilled in the art. In use, the proppant is
suspended in the fracturing fluid. Thus, interactions of the
proppant and the fluid will greatly affect the stability of the
fluid in which the proppant is suspended. The fluid needs to remain
viscous and capable of carrying the proppant to the fracture and
depositing the proppant at the proper locations for use. However,
if the fluid prematurely loses its capacity to carry, the proppant
may be deposited at inappropriate locations in the fracture or the
well bore. This may require extensive well bore cleanup and removal
of the mispositioned proppant. It is also important that the fluid
breaks (undergoes a reduction in viscosity) at the appropriate time
after the proper placement of the proppant. After the proppant is
placed in the fracture, the fluid shall become less viscous due to
the action of breakers (viscosity reducing agents) present in the
fluid. This permits the loose and curable proppant particles to
come together, allowing intimate contact of the particles to result
in a solid proppant pack after curing. Failure to have such contact
will give a much weaker proppant pack. Foam, rather than viscous
fluid, may be employed to carry the proppant to the fracture and
deposit the proppant at the proper locations for use. The foam is a
stable foam that can suspend the proppant until it is placed into
the fracture, at which time the foam breaks. Agents other than foam
or viscous fluid may be employed to carry proppant into a fracture
where appropriate. Also, resin coated particulate material (e.g.,
sands) may be used in a wellbore for "sand control." In this use, a
cylindrical structure is filled with the proppants (e.g., resin
coated particulate material) and inserted into the wellbore to act
as a filter or screen to control or eliminate backwards flow of
sand, other proppants, or subterranean formation particles.
Typically, the cylindrical structure is an annular structure having
inner and outer walls made of mesh. The screen opening size of the
mesh being sufficient to contain the resin coated particulate
material within the cylindrical structure and let fluids in the
formation pass therethrough.
[0104] Fluid compositions useful in methods of the disclosure may
be used with and/or employ any of a number of well treatments or
well completions. As used herein the terms "well completion" and
"completion" are used as nouns except when referring to a
completion operation. Well completions within the disclosure
include, but are nor limited to, casing completions, commingled
completions, hydraulic fracturing, coiled tubing completions, dual
completions, high temperature completions, high pressure
completions, high temperature/high pressure completions, multiple
completions, natural completions, artificial lift completions,
partial completions, primary completions, tubingless completions,
and the like.
[0105] In the oilfield context, a "wellbore" may be any type of
well, including a producing well, a non-producing well, an
injection well, a fluid disposal well, an experimental well, an
exploratory well, and the like. Wellbores may be vertical,
horizontal, deviated some angle between vertical and horizontal,
and combinations thereof, for example, a vertical well with a
non-vertical component.
[0106] In an implementation of the methods of the present
invention, a wellbore treatment can be designed considering
characteristics of the target subterranean formation, desired
outcome resulting from contacting the formation with the fluid
composition, chemistry and characteristics of the fluid
composition, well-bore geometry, and equipment to be used to inject
the fluid composition to determine the appropriate concentration
and type of components to use to in the methods embodied
herein.
[0107] In performing an operation at a well-bore, the first and
second components are typically metered, either together or
separately, into the fluid composition at a surface location prior
to injection into the well-bore. If proppant is provided, the first
and second components are normally metered into the fluid
composition separately from the proppant. In many cases the fiber
concentration in the fluid would be less than 5% by weight of the
proppant, often less than about 2% by weight of the proppant, and
on occasion less than about 1% by weight of the proppant. Generally
the ratio of fiber to proppant would remain the same throughout the
operation, with the fiber concentration increasing in proportion to
the proppant concentration in the fluid composition. It is
advantageous to add the first and second components to the fluid
composition in a continuous process. Use of high shear-rate mixers
is preferred to rapidly mix the first and second components with
the fluid composition, and optionally proppant, to disperse the
components thoroughly within the fluid composition. As the methods
of the present invention are conducive to rapid turnaround, field
operations would be aided by the use of dual choke or dual flow
equipment to permit quick fluid production from the well-bore.
[0108] Although only a few exemplary embodiments of this disclosure
have been described in detail above, those skilled in the art will
readily appreciate that many modifications are possible in the
exemplary embodiments without materially departing from the novel
teachings and advantages of this disclosure. Accordingly, all such
modifications are intended to be included within the scope of this
disclosure as defined in the following claims.
* * * * *