Note: Descriptions are shown in the official language in which they were submitted.
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Methods of Contacting and/or Treating a Subterranean Formation
[0001] Background
[0002] 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.
[0003] 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.
[0004] 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.
[0005] 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.
[0006] 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.
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[0007] US Patent !slumbers 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.
[0008] 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.
[0009] Summary
[0010] In accordance with the present disclosure, methods of contacting a
subterranean formation
are described which may 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.
[0011] One aspect of the disclosure are methods 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 (in some embodiments, greater than 1:5, 1:10,
1:50,
1:100, or even 1:150);
forming a network comprising the first component; and
binding the network with the second component.
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[0012] 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 x 106
dynes/cm2 (3 x 105
N/m2) at a frequency of about 1 Hz at a temperature greater than -60 C. In
certain methods the fluid
composition may further comprise proppant.
[0013] Another aspect of the disclosure are methods of contacting a
subterranean formation
comprising:
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:
a core having a softening point of at least 130 C; and
a sheath having a softening point up to 130 C.
[0014] Another aspect of the disclosure are methods of contacting a
subterranean formation
comprising:
injecting into a well-bore intersecting the subterranean formation a fluid
composition comprising a multicomponent article dispersed in a carrier fluid
wherein
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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:
a core having a softening point of at least 130 C;
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
an intermediate sheath positioned between the core and the outer sheath, the
intermediate sheath having a softening point up to 130 C.
[0015] Another aspect of the disclosure are methods 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.
[0016] 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
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first or second components may be selected from polylactic acid and
polyglycolic acid. In certain
embodiments, the fluid composition may further comprise proppant.
[0017] Another aspect of the disclosure are methods 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 x 106 dynes/cm2 (3 x 105 N/m2)
at a
frequency of about 1 Hz at a temperature greater than -60 C.
[0018] 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.
[0019] Another aspect of the disclosure are methods of treating a subterranean
formation
comprising:
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;
forming a network comprising the first component; and
binding the network with the second component, wherein
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).
[0020] 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
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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 x 106 dynes/cm2 (3 x 105 N/m2)
at a frequency of
about 1 Hz at a temperature greater than -60 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.
[0021] Yet another aspect of the disclosure are methods 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 (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 x 106 dynes/cm2 (3 x 105 N/m2) at a frequency of about 1 Hz at a
temperature
greater than -60 C;
forming a network comprising the first component;
binding the network with the second component; and
contacting the subterranean formation with the fluid composition.
[0022] 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
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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.
[0023] 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.
[0024] 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 polyolef in 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
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downhole temperature, such as the bottomhole static temperature (BHST), and
have
a modulus of less than 3 x106 dynes/cm2 (3 x 105 N/m2) at a frequency of about
1 Hz
at a temperature greater than -60 C.
[0024a] The present disclosure further relates to 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 and at least a portion of the second component being provided as
multi-
component core sheath fibers; after injecting, forming a network comprising
the first
component; and binding the network with the second component; wherein the
network is in the form of netting that allows oil, gas, or other fluids to
pass through
relative to particulate matter.
[0024b] The present disclosure further relates to 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 in multi-component core sheath fibers prior to
injection; and after injecting, forming a network comprising at least one
first
component in direct contact with another first component; and binding the
network
with the second component; wherein the network is in the form of netting that
allows
oil, gas, or other fluids to pass through relative to particulate matter.
[0024c] The present disclosure further relates to 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 at least a portion of
the first
component and at least a portion of the second component are provided in multi-
component core sheath fibers; after injecting, forming a network comprising
the first
component; and binding the network with the second component, wherein the
second
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component is selected to be tacky at a specific downhole temperature and have
a
modulus of less than 3 x 106 dynes/cm2 (3 x 105 N/m2) at a frequency of about
1 Hz
at a temperature greater than -60 C; and wherein the network is in the form of
netting
that allows oil, gas, or other fluids to pass through relative to particulate
matter.
[0024d] The present disclosure further relates to 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, wherein at
least a
portion of the first component and at least a portion of the second component
are
provided in multi-component core sheath fibers, wherein the second component
is
selected to be tacky at a specific downhole temperature and have a modulus of
less
than 3 x 106 dynes/cm2 (3 x 105 N/m2) at a frequency of about 1 Hz at a
temperature
greater than -60 C; contacting the subterranean formation with the fluid
composition;
subsequently, forming a network comprising the first component; and binding
the
network with the second component; wherein the network is in the form of
netting that
allows oil, gas, or other fluids to pass through relative to particulate
matter.
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[0025] 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 flowbadc from that
percentage of fractures.
The percentage may range from 10 percent to 100 percent.
[0026] 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.
[0027] 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.
[0028] 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.
[0029] 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.
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[0030] Brief Description of the Drawings
[0031] 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:
[0032] FIGS. 1A-1D are schematic cross-sections of four prior art
multicomponent fibers useful in
methods of the disclosure;
[0033] FIGS. 2A-2G are schematic perspective views of various multicomponent
articles useful in
methods of the disclosure;
[0034] FIG. 3 is a schematic plot of modulus (dynes/cm2) vs. temperature ( 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
[0035] FIG. 4 is a plot of fiber concentration versus proppant pack flow
during flowback tests.
[0036] Detailed Description
[0037] 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.
[0038] 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.
[0039] 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.
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[0040] 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.
[0041] 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.
[0042] 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.
[0043] 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.
[0044] 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
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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.
[0045] 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.
[0046] 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.
[0047] 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
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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.
[0048] 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.
[0049] 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, NC.
[0050] 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,
12
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New Castle, DE), 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
20mm parallel plates of a
rheometer and a sinusoidal frequency of 1 Hz at 1% strain applied over a
temperature range of 100-
150 C. Results are shown in FIG. 3 plotted as modulus (dynes/cm2) vs.
temperature ( 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 x 106
dynes/cm2 (3 x 105 N/m2) at a frequency of about 1 Hz.
[0051] Methods and systems for applying heat to a region of a wellbore are
known and described for
example in US Patent Number 6,023,554 (George et al.) and in Published US
Patent Application
Publication Number 2005/0269090 (Vinegar et al.).
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.
[0052] 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.
[0053] Tackifiers typically comprise an organic material having a glass
transition temperature of no
less than about 120 `C. (in certain embodiments, no less than about 150 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 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 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
13
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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 C., in some embodiments, no less than
about 150 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, AR.
Other suitable tackifiers and their ingredients are discussed in US Patent
Number 5,362,566 (George
et al.).
[0054] 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.
[0055] 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
=
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polyamide or PET shell as sheath 44. A second example may be a polyamide core
covered by a
phenolic or melamine based resin system.
[0056] 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.
[0057] 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.
[0058] 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.
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[0059] 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.
[0060] 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, MN 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, MI.
[0061] 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
x 106 dynes/cm2 (3 x 105 N/m2) at a frequency of about 1 Hz at a temperature
greater than -602C, 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.
[0062] Suitable multicomponent articles are also described, for example, in US
Provisional Patent
Application having Serial Number 61/014,004 (Attorney Docket No. 63584US002;
entitled "Multi-
Component Fibers"), filed the same date as the instant application.
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[0063] 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.
[0064] Example
[0065] 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 x 5.25 in (13.3 cm
x 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.
[0066] 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, WI, 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 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.
[0067] 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 Minnesota, while
the bicomponent
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fiber was a nylon core with SURLYNTM (mark of DuPont Corporation) sheath
provided by 3M
Company, St. Paul, Minnesota. 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.
[0068] 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.
[0069] 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.
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[0070] 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.
[0071] 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.
[0072] 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).
[0073] 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.
[0074] 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 (FICI), 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 maybe
used in these
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=
applications, as the acidic solution may decompose the composition selectively
rather than other
components or geologic formations.
[0075] 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.
[0076] 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.
[0077] 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 US Patent Number 5,082,720 (Hayes). 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.
[0078] 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.
[0079] 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.
[0080] 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
CA 02708396 2015-06-02
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option is to use an electrical submersible pump ("ESP"), such as pumping
systems known under the
trade designation AXIATM, from Schlumberger Technology Corporation, Sugar
Land, TX.
[0081] 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 US Patent
Number 3,929,191 (Graham et al.).
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 US Patent
Number 4,068,718 (Cooke et al.).
[0082] Other suitable proppants are described, for example, in US Patent
Numbers 6,406,789
(McDaniel et al.); 6,582,819 (McDaniel et al.); and 6,632,527(McDaniel et
al.).
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., US Patent
Number 4,977,116
(Rumpf et al.); EP Patents 0 087 852, granted April 2, 1986, 0 102
761, published March 14, 1984, or 0 207 668, granted April 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 US Patent Number 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 (US Patent Number 5,420,174 (Deprawshad et
al); US Patent Number
5,218,038 (Johnson et al.); US Patent Number 5,639,806 (Johnson et al.);
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
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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 F.(82 C.)) and high pressure (>6,000 psi
(41MPa)) 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 F (54 C.),
or even less than
100 F (38 C .).
[0083] 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
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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.
[0084] 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.
[0085] 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. Wel!bores may be vertical, horizontal, deviated some angle between
vertical and horizontal,
and combinations thereof, for example, a vertical well with a non-vertical
component.
[0086] 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.
[0087] 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 /0 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
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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.
[0088] 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.
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