U.S. patent application number 14/844721 was filed with the patent office on 2015-12-31 for downhole polymer foam applications.
The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Carlos Abad, Alexander D. Wilson.
Application Number | 20150376999 14/844721 |
Document ID | / |
Family ID | 47506841 |
Filed Date | 2015-12-31 |
United States Patent
Application |
20150376999 |
Kind Code |
A1 |
Abad; Carlos ; et
al. |
December 31, 2015 |
DOWNHOLE POLYMER FOAM APPLICATIONS
Abstract
A method of treating a subterranean formation penetrated by a
wellbore by contacting an energized fluid with the subterranean
formation; and reducing a partial pressure of the energized fluid
by an amount sufficient to form polymeric foam structure within the
subterranean formation
Inventors: |
Abad; Carlos; (Aberdeen,
GB) ; Wilson; Alexander D.; (Cambridge, GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Houston |
TX |
US |
|
|
Family ID: |
47506841 |
Appl. No.: |
14/844721 |
Filed: |
September 3, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13544515 |
Jul 9, 2012 |
9140107 |
|
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14844721 |
|
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61571995 |
Jul 8, 2011 |
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Current U.S.
Class: |
166/278 ;
166/280.1; 166/300 |
Current CPC
Class: |
E21B 43/168 20130101;
C09K 8/38 20130101; C09K 8/588 20130101; E21B 43/166 20130101; C09K
8/536 20130101; E21B 43/164 20130101; C09K 8/80 20130101; C09K
8/703 20130101; E21B 43/04 20130101; E21B 43/267 20130101; E21B
43/16 20130101; C09K 8/518 20130101; E21B 43/26 20130101; C09K 8/94
20130101 |
International
Class: |
E21B 43/16 20060101
E21B043/16; E21B 43/04 20060101 E21B043/04; C09K 8/80 20060101
C09K008/80; C09K 8/70 20060101 C09K008/70; C09K 8/588 20060101
C09K008/588; C09K 8/536 20060101 C09K008/536; E21B 43/267 20060101
E21B043/267; E21B 43/26 20060101 E21B043/26 |
Claims
1.-18. (canceled)
19. A method comprising: providing a completion in a subterranean
formation comprising a wellbore connected to the subterranean
formation; placing a polymer component into the wellbore; pumping
an energized fluid into the wellbore; reducing the pressure of the
energized fluid; allowing the energized fluid to escape from the
wellbore, forming a polymeric foam structure.
20. The method of claim 19 wherein the completion comprises a
screen, located in the wellbore, such as to provide an annular
space between the wellbore and the screen.
21. The method of claim 19 wherein the completion comprises at
least one of an open hole, a cased hole, a gravel pack, a propped
hydraulic fracture, or a frac and pack.
22. The method of claim 20 wherein the polymer component is placed
into the annular space between the wellbore and the screen.
23. The method of claim 19 wherein the energized fluid comprises a
gas component selected from the group consisting of nitrogen, air,
argon, carbon dioxide, helium, krypton, xenon, natural gas,
methane, ethane, propane, and mixtures thereof.
24. The method of claim 19 wherein the energized fluid comprises a
polymer swelling solvent.
25. The method of claim 19 wherein the polymer component comprises
a reactive polymer.
26. The method of claim 19 wherein the polymer component comprises
one or more polymer materials.
27. The method of claim 19 wherein the polymer component further
comprises a catalyst.
28. The method of claim 19 wherein the energized fluid further
comprises at least one solid selected from the group consisting of
inorganic solids, organic solids, and combinations thereof; and
wherein the polymeric foam structure further comprises the at least
one solid.
29. The method of claim 28 wherein the at least one solid is
selected from the group consisting of a filler material, beads,
ceramics, sand, salts, bauxite, glass, glass beads, metal beads,
fibres, thermoplastic fibres, polylactic acid polyester fibers,
natural organic fibres, synthetic polymer fibres, polyglycolic acid
polyester fibres, polyvinyl alcohol fibres, polyester fibres,
polyaramide fibres, polyamide fibres, novoloid fibres,
novoloid-type fibres, fibrillated synthetic organic fibres, ceramic
fibres, inorganic fibres, metal fibres, metal filaments, carbon
fibres, glass fibres, natural polymer fibres, thermoplastic
pellets, thermoset pellets, thermoset beads, wood chips, extruded
solids, sand coated with a polymer resin, bauxite coated with a
polymer resin, ceramics coated with a polymer resin, and mixtures
thereof.
30. The method of claim 19 further comprising one of etching or
wormholing the polymeric foam structure with a treatment selected
from an acid treatment or an oxidizer treatment.
31. The method of claim 30 wherein the treatment of the polymeric
foam structure comprises contacting the polymeric foam structure
with at least one treatment component selected from the group
consisting of hydrochloric acid, formic acid, acetic acid, mud
acid, citric acid, nitric acid, sulfuric acid, hydrofluoric acid,
acid-precursor compounds capable of generating acids selected from
the group consisting of organic esters, ammonium bifluoride,
persulfates, bromides, organic peroxides, organic peresters, and
mixtures thereof.
32. The method of claim 29 wherein the polymer component comprises
a polymer material selected from the group consisting of i) a
reactive polymer, ii) a thermoplastic non-reactive polymer, and
iii) combinations thereof.
33. The method of claim 32 wherein the reactive polymer is selected
from the group consisting of epoxy resin, phenoxy resin, phenol
formaldehyde resin, melamine formaldehyde resin, polysiloxane,
reactive polyester resin, and combinations thereof; and wherein the
thermoplastic non-reactive polymer is selected from the group
consisting of polyvinyl acetate and copolymers, polylactic acid,
perfluoroacrylate (PFA), polyglycolic acid, polyhydroxybutyrate,
bisphenol A (acetone) polycarbonate, bisphenol F (formaldehyde)
polycarbonate, polymethyl acrylate, polymethyl methacrylate,
polyethylene carbonate, polyethylene and copolymers, polypropylene
and copolymers, polystyrene and copolymers, polyoxymethylene and
copolymers, and combinations thereof.
34. The method of claim 19 wherein the method comprises at least
one of a fracturing application and a wellbore consolidation.
35. The method of claim 19 wherein the method comprises at least
one of conformance control and enhanced oil recovery.
36. The method of claim 19 wherein the polymeric foam structure
comprises a thermoplastic foam structure.
37. The method of claim 19 wherein the method comprises placing the
polymeric foam structure in a fracture in the subterranean
formation.
38. The method of claim 19 wherein the method comprises placing the
polymeric foam structure in a gravel pack in the subterranean
formation.
Description
PRIORITY
[0001] The present application claims priority to U.S. Provisional
Application No. 61/571,995 filed Jul. 8, 2011, which is
incorporated by reference herein in its entirety.
BACKGROUND
[0002] Hydrocarbons (oil, natural gas, etc.) are obtained from a
subterranean geologic formation (a "reservoir") by drilling a well
that penetrates the hydrocarbon-bearing formation. In the process
of recovering hydrocarbons from subterranean formations, it is
common practice to treat a hydrocarbon-bearing formation with a
pressurized fluid to provide flow channels, i.e., to fracture the
formation, or to use such fluids to transport and place proppant to
facilitate flow of the hydrocarbons to the wellbore. It is also a
common practice to stabilize sand prone formations by means of
consolidation treatments, or gravel packing treatments.
[0003] Well treatment fluids, particularly those used in
fracturing, may comprise a water or oil based fluid incorporating a
thickening agent, normally a polymeric material. Gases, such as
carbon dioxide (CO.sub.2), may be used to fracture alone or in
combination with nitrogen (N.sub.2) to place the proppant. Foamed
materials have been employed in many different applications, such
as, for example isolation (polystyrene, or polyurethane), or even
structural (aluminum foam in aircraft plans). However, foamed
materials in the oilfield are often associated to the use of an
energizing gas such as nitrogen (N.sub.2), methane or CO.sub.2 in
aqueous polymeric solutions such as foamed fracturing fluids, or
particle slurries, such as foamed cement.
BRIEF DESCRIPTION OF DRAWINGS
[0004] FIG. 1 is a photograph of the energized fluid of Example
1.
[0005] FIG. 2 is a photograph of the polymer foam of Example 1.
[0006] FIG. 3 is a photograph of the polymer foam of Example 2.
[0007] FIG. 4 is a photograph of the polymer foam of Example 3.
[0008] FIG. 5 is a photograph of the polymer foam of Example 3.
[0009] FIG. 6 is a phase diagram.
SUMMARY
[0010] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter.
[0011] In some embodiments, the present disclosure describes a
method of treating a subterranean formation penetrated by a
wellbore by contacting an energized fluid with the subterranean
formation; and reducing a partial pressure of the energized fluid
by an amount sufficient to form polymeric foam structure within the
subterranean formation
DETAILED DESCRIPTION
[0012] In the following description, numerous details are set forth
to provide an understanding of the present disclosure. However, it
may be understood by those skilled in the art that the methods of
the present disclosure may be practiced without these details and
that numerous variations or modifications from the described
embodiments may be possible.
[0013] At the outset, it should be noted that in the development of
any such actual embodiment, numerous implementation--specific
decisions may be made to achieve the developer's specific goals,
such as compliance with system related and business related
constraints, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort
might be complex and time consuming but would nevertheless be a
routine undertaking for those of ordinary skill in the art having
the benefit of this disclosure. In addition, the composition
used/disclosed herein can also comprise some components other than
those cited. In the summary and this detailed description, each
numerical value should be read once as modified by the term "about"
(unless already expressly so modified), and then read again as not
so modified unless otherwise indicated in context. Also, in the
summary and this detailed description, it should be understood that
a range listed or described as being useful, suitable, or the like,
is intended to include support for any conceivable sub-range within
the range at least because every point within the range, including
the end points, is to be considered as having been stated. For
example, "a range of from 1 to 10" is to be read as indicating each
possible number along the continuum between about 1 and about 10.
Furthermore, one or more of the data points in the present examples
may be combined together, or may be combined with one of the data
points in the specification to create a range, and thus include
each possible value or number within this range. Thus, even if a
specific data points within the range, or even no data points
within the range, are explicitly identified or refer to a few
specific, it is to be understood that inventors appreciate and
understand that any conceivable data point within the range is to
be considered to have been specified, and that inventors possessed
knowledge of the entire range and each conceivable point and
sub-range within the range.
[0014] The present disclosure relates generally to a method of
treating a subterranean formation penetrated by a wellbore by
contacting an energized fluid with the subterranean formation; and
reducing a partial pressure of the energized fluid by an amount
sufficient to form polymeric foam structure within the subterranean
formation. For example, the energized fluid may be introduced,
injected or conveyed into a subterranean formation by way of a
wellbore that penetrates a subterranean formation, such as a
water-bearing subterranean formation.
[0015] The subject matter of the present application also relates
to well servicing methods that may be applied at any time in the
life cycle of a reservoir or field to enhance the value of oil and
gas assets through reduced water handling cost, improved
hydrocarbon productivity and/or higher recovery factors. As used
herein, the term "field" includes land based (surface and
sub-surface) and sub-seabed applications. The term "oilfield," as
used herein, includes hydrocarbon oil and gas reservoirs, and
formations or portions of formations where hydrocarbon oil and gas
are expected but may ultimately contain water, brine, or some other
composition.
[0016] As discussed above, the energized fluid may be contacted
with the subterranean formation, such as, for example, with a
surface of the subterranean formation and/or wellbore. For purposes
of this disclosure, the term "energized fluid" or "foam" is
understood to comprise a fluid which when subjected to a low
pressure environment liberates or releases gas from solution or
dispersion (for example, a liquid containing dissolved gases) as
known in the art. Foam or energized fluids are stable mixture of
gases and liquids that form a two-phase system. Foam and energized
fracturing fluids are generally described by their foam quality,
i.e. the ratio of gas volume to the foam volume. If the foam
quality is between 52% and 95%, the fluid is usually called foam.
Above 95%, foam is generally changed to mist. In the present patent
application, the term "energized fluid" also refers to any stable
mixture of gas and liquid, regardless of the foam quality.
[0017] Aspects of the subject matter described herein include
energized fluids comprising any of:
[0018] (a) Liquids that at bottom hole conditions of pressure and
temperature are close to saturation with a species of gas. For
example the liquid can be aqueous and the gas nitrogen or carbon
dioxide. Associated with the liquid and gas species and temperature
is a pressure called the bubble point, at which the liquid is fully
saturated. At pressures below the bubble point, gas emerges from
solution;
[0019] (b) Foams, consisting generally of an aqueous phase and a
gas phase, or a solid phase and a gas phase. At high pressures the
foam quality is typically low (i.e., the non-saturated gas volume
is low), but quality (and volume) rises as the pressure falls.
Additionally, the aqueous phase may have originated as a solid
material and once the gas phase is dissolved into the solid phase,
the viscosity of solid material is decreased such that the solid
material becomes a liquid; or
[0020] (c) Liquefied gases.
[0021] Fluid technologies incorporating a gaseous component or a
supercritical fluid to form an energized fluid are described in
U.S. Pat. Nos. 2,029,478, 3,937,283, 6,192,985 and U.S. Patent
Publication Nos. 20060178276, 20060166836, 20070238624,
20070249505, 20070235189, 20070215355, 20050045334 and 20070107897,
each of which are incorporated by reference herein in their
entirety.
[0022] In embodiments, the energized fluid is comprised of a gas
component and a polymer component. The gas component may be mixed
with and/or partially dissolved in the gas component. The gas
component of the energized fluid may be, for example, nitrogen,
air, argon, carbon dioxide, helium, krypton, xenon, natural gas,
methane, ethane, propane, and any mixtures thereof. The energized
fluids that may be used within aspects of the present application
include any stable mixture of gas phase and liquid phase. More
preferably the gas component comprises carbon dioxide, in any
quality readily available. The gas component may assist in the
clean-up process of the treated formation. The energized fluid may
contain from about 10% to about 90% volume gas component based upon
total fluid volume percent, preferably from about 30% to about 80%
volume gas component based upon total fluid volume percent, and
more preferably from about 40% to about 70% volume gas component
based upon total fluid volume percent.
[0023] In the foregoing, the characteristics of supercritical
fluids such as those described in the present application are
exemplified by describing the properties of supercritical carbon
dioxide. The below description of the supercritical characteristics
of carbon dioxide should not be considered as limiting the scope of
the below embodiments only to carbon dioxide, but also encompass
all of the gas components of the application.
[0024] Supercritical carbon dioxide is a fluid state of carbon
dioxide where it is held at or above its critical temperature and
critical pressure. Carbon dioxide usually behaves as a gas in air
at standard temperature and pressure (STP), or as a solid called
dry ice when frozen. If the temperature and pressure are both
increased from STP to be at or above the critical point for carbon
dioxide, it can adopt properties somewhere between a gas and a
liquid. In other words, it behaves as a supercritical fluid above
its critical temperature (31.1 deg C.) and critical pressure (72.9
atm/7.39 MPa), expanding to fill its container like a gas but with
a density like that of a liquid.
[0025] As used herein, the term "critical point" refers to the
vapor--liquid critical point of a material, above which distinct
liquid and gas phases do not exist.
[0026] As shown in the phase diagram in FIG. 6, the critical point
is point at which the phase boundary between liquid and gas
terminates. In water, the critical point occurs at around 647 degK
(374 deg C.; 705 deg F. critical temperature) and 22.064 MPa (3200
PSIA or 218 atm, critical pressure), in carbon dioxide occurs at
around 303.4 degK (31.1 deg C., 88 deg F., critical temperature)
and 7.39 MPa (1070 PSIA or 72.9 atm, critical pressure),
[0027] As a substance approaches critical temperature, the
properties of its gas and liquid phases converge, resulting in only
one phase at the critical point: a homogeneous supercritical fluid.
Furthermore, the heat of vaporization is zero at and beyond this
critical point, and thus no distinction exists between the two
phases. Above the critical temperature, a liquid typically cannot
be formed by an increase in pressure, even though a solid may be
formed under sufficient pressure. The critical pressure is the
vapor pressure at the critical temperature. Above the critical
point the solubilizing properties of the substance or mixture can
be significantly different from those of the liquid or gas phases.
Table 1 below specifies the critical temperature and critical
pressure for some of the gas component mentioned above, and some
other examples.
TABLE-US-00001 TABLE 1 Critical Temperature and Critical Pressure
of Gas Components Substance Critical temperature Critical pressure
(absolute) Argon -122.4.degree. C. (150.8 K) 48.1 atm (4,870 kPa)
Ammonia 132.4.degree. C. (405.6 K) 111.3 atm (11,280 kPa) Bromine
310.8.degree. C. (584.0 K) 102 atm (10,300 kPa) Chlorine
143.8.degree. C. (417.0 K) 76.0 atm (7,700 kPa) Ethanol 241.degree.
C. (514 K) 62.18 atm (6,300 kPa) Fluorine -128.85.degree. C.
(144.30 K) 51.5 atm (5,220 kPa) Helium -267.96.degree. C. (5.19 K)
2.24 atm (227 kPa) Hydrogen -239.95.degree. C. (33.20 K) 12.8 atm
(1,300 kPa) Krypton 63.8.degree. C. (209.4 K) 54.3 atm (5,500 kPa)
CH.sub.4 (Methane) -82.3.degree. C. (190.9 K) 45.79 atm (4,640 kPa)
Neon -228.75.degree. C. (44.40 K) 27.2 atm (2,760 kPa) Nitrogen
146.9.degree. C. (126.3 K) 33.5 atm (3,390 kPa) Oxygen
118.6.degree. C. (154.6 K) 49.8 atm (5,050 kPa) CO.sub.2
31.04.degree. C. (304.19 K) 72.8 atm (7,380 kPa) N.sub.2O
36.4.degree. C. (309.6 K) 71.5 atm (7,240 kPa) Xenon 16.6.degree.
C. (289.8 K) 57.6 atm (5,840 kPa) Water 100.0.degree. C. (303.4 K)
218 atm (22,064 kPa)
[0028] The polymer component may be dissolved in the gas component
under supercritical conditions. The dissolution may occur with or
without mixing. The supercritical conditions vary depending on the
gas component or the components of a gas mixture. However, as used
herein, the phrase "supercritical conditions" refers to the
conditions required to reach a state that does not have any
distinct liquid, solid or gas phases. As a material approaches
critical temperature and/or critical pressure, the properties of
its gas and liquid phases converge, resulting in only single phase
at the critical point (also referred to as a homogeneous
supercritical fluid). Such conditions typically occur by increasing
the temperature and pressure of the material above its critical
point. At these conditions, the material can effuse through solids
like a gas or dissolve materials like a liquid. Furthermore, at
conditions close to the critical point, subtle changes in the
temperature and/or pressure of the material can result in
significant changes in a material's physical property, such as
density, and thus allowing many properties of a supercritical fluid
to be "fine-tuned".
[0029] As discussed above, the polymer component may be swollen or
plasticized by a gas component at supercritical conditions. This
may form a relatively low viscosity slurry, which may also contain
a catalyst used to set the polymer if the choice is a reactive.
Examples of catalysts include acids, bases, metals, amines,
anhydrides, carboxylic acids, sulfur, mercaptanes, alcohols, and
the like. The use of such catalysts may enable high strength and
high resistance foam to be formed downhole after the gas component
has been released. If present, the amount of catalyst in the
composition may be from about 0.001% to about 5%, from about 0.1%
to about 5%, from about 0.5% to about 4.0%, from about 1.0% to
about 2.5% and form about 1.0% to about 2.0%, based on polymer
weight.
[0030] A catalyst may also be used to crosslink the thermoplastic
solids. In particular embodiments the energized fluid may also be a
solids laden slurry comprising one or more inorganic and/or organic
solids that may become part of the foam upon polymerization of the
polymer component in the energized fluid. Examples of inorganic
solids may be ceramics, sand, bauxite, glass beads, metal beads,
and the like. Examples of organic solids may be thermoplastic
pellets or beads, thermoset pellets or beads, wood chips, and the
like. Solids such as those described below can be added to the
slurry in a high pressure conveyor such as an extruder or high
pressure pump, and can be transported with the slurry. In another
embodiment the solids may be extruded together with the
thermoplastic polymer prior to the addition of the gas component in
the form of pellets. In another embodiment the inorganic solids,
such as sand, bauxite or ceramics are coated with polymer resins.
In another embodiment the solids may be slurried with the polymer
resin. A conductive path results from the evaporation of the gas
component in the polymer.
[0031] In another embodiment, the thermoplastic polymer or the
thermoset produced downhole may be etched or wormholed with an acid
or oxidizer treatment after the main foam treatment is completed.
Examples of acids include hydrochloric acid, formic acid, acetic
acid, mud acid, citric acid, nitric acid, sulfuric acid,
hydrofluoric acid, and other compounds capable of generating such
acids, such as organic esters, or ammonium bifluoride. Examples of
oxidizers include persulfates such as ammonium, sodium, or
potassium persulfate, bromides, organic peroxides, organic
peresters, and the like. The amount of the acid and/or oxidizer may
be present in the composition in an amount of from about 0.01% to
about 5%, from about 0.5% to about 4.0%, from about 1.0% to about
2.5% and form about 1.0% to about 2.0% based on polymer weight.
[0032] The viscosity that can be achieved with such supercritical
fluid polymeric solutions may be reduced unless high concentrations
of the polymer component are considered. For example, the
concentration of the polymer component may be from about 0.1% to
about 20%, from about 0.5% to about 20%, from about 1.0% to about
15% and form about 5.0% to about 10.0% based upon the weight of the
energized fluid. On the other hand, only a select amount of
polymers have been found to date to dissolve in a gas component,
such as CO.sub.2, at concentrations significant enough to generate
viscosity. The solubility of many of those polymers that dissolve
in the gas component is only significant for low molecular weight
polymers and oligomers, such as, for example, polymer and oligomers
having a molecular weight of from about 100 Daltons to about
100,000 Dalton or from about between 500 Daltons and 30,000
Daltons.
[0033] In another aspect of the application, the gas or gas mixture
in supercritical conditions becomes a solvent for the polymer. The
description of the supercritical component as a solvent is based on
the fact that complete polymer solubility is not always required in
the disclosed wellbore applications, and thus it will suffice with
the gas component "swelling" the polymers, oligomers and
copolymers. As used herein, the term "swell" does not necessarily
imply the use of a fully dissolved crosslinked polymer that is
solvated completely and at a molecular level dissolves perfectly in
the solvent, but rather, a polymer that is not fully dissolved, but
rather plasticized, and whose hydrodynamic volume may not
necessarily increase in the presence of the gas component, and
therefore is only "swollen" by the solvent, and not "dissolved". In
some embodiments the term "swell" will be used indistinctly from
the term "plasticize". This term may apply to those polymers or
oligomer that, at the pressure and temperature of the experiment or
treatment, do not completely dissolve in the gas component, but
show significant compatibility with the solvent, so as to allow gas
component molecules to permeate, and "plasticize" the polymer
matrix.
[0034] As defined herein, the term "polymer" or "polymer component"
refers to both high molecular weight polymers (and oligomers) and
low molecular weight polymers (and oligomers), both linear,
branched, star, crosslinked, dendrimeric.
[0035] The polymer component may be a reactive polymer, such as,
for example, an epoxy resin, a phenoxy resin, a phenol formaldehyde
resin, a melamine formaldehyde resin, a polysiloxane, a reactive
polyester resin, and combinations thereof. The polymer component
may also be a thermoplastic non-reactive polymer such as, for
example, polyvinyl acetate and copolymers, polylactic acid,
perfluoroacrylate (PFA), polyglycolic acid, polyhydroxybutyrate,
bisphenol A (acetone) polycarbonate, bisphenol F (formaldehyde)
polycarbonate, polymethyl acrylate and similar polymers, polymethyl
methacrylate and similar polymers, polyethylene carbonate,
polyethylene and copolymers, polypropylene and copolymers,
polystyrene and copolymers, polyoxymethylene and copolymers and
combinations thereof.
[0036] The polymer component may comprise one or more polymers,
such as for example, from about 2 to about 5 different polymer
materials. For example, the polymer component may be a mixture of
polyvinyl acetate and polymethyl methacrylate. The two polymers, if
the energized composition contains two polymers, may be present in
any suitable amount, such as, for example from about 1 wt % first
polymer to about 99 wt % second polymer, from about 10 wt % first
polymer to about 90 wt % second polymer, from about 25 wt % first
polymer to about 75 wt % second polymer, from about 50 wt % first
polymer to about 50 wt % second polymer and from about 40% first
polymer to about 60 wt % second polymer, based upon the total
polymer weight in the energized fluid. Any of the polymers
discussed above may be considered as the first or second polymers
if the two polymers are present in the energized fluid.
[0037] The gas component may also be used as a carrier for a solid
polymer component or even as a filler for other materials such
thermoplastic fibers, beads, sand, salts, metal beads and fibers.
Such a solid material may or may not be in a treatment.
[0038] The energized fluid may also comprises an inorganic solid
slurry, a swollen polymer matrix, or a swollen polymer and
inorganic solid slurry such where the gas component is selected as
the solvent form the foam. Moreover, it may be appropriate that, as
the solvent volatilizes, the desired polymer solution viscosity is
maintained, or the desired polymer melt strength at downhole
temperature and pressure conditions is properly managed. This
rheological characteristic of the polymer supercritical gas mixture
is referred to herein as "melt viscosity". A suitable "melt
viscosity" may be achieved by (1) a selection of the polymer
component and the gas component, (2) by a selection of the polymer
and inorganic solid concentration with respect to the gas
component, (3) a selection of the polymer molecular weight or (4) a
selection of the crosslinker concentration. Too low (i.e., below
about 1000 cP) of a "melt viscosity" may result in the gas
component easily escaping the fluid, and not resulting in an
expanded foam contacting properly the formation. Too high of a
"melt viscosity" (i.e., above about 1,000,000 cP) may result in the
gas component not being able to escape the fluid, and not resulting
in an expanded foam contacting properly the formation. The melt
viscosity may be from about 1000 cP to about 1,000,000 cP
[0039] As discussed above, to induce the supercritical conditions,
the partial pressure of the gas component in the energized fluid
(or the energized fluid itself) may be increased by at least 900
psi (6,205.28 kPa), at least 1500 psi (10,342.14 kPa), at least
about 2000 psi (13,789.51 kPa), at least about 2500 psi or at least
about 3000 psi. The partial pressure of the gas component in the
energized fluid (or the energized fluid itself) may also be
increased to a pressure that is at least 900 psi (6,205.28 kPa), at
least 1500 psi (10,342.14 kPa), at least about 2000 psi (13,789.51
kPa), at least about 2500 psi (17,236.89 kPa) or at least about
3000 psi (20,684.27 kPa) greater than the critical pressure of the
gas component. This increase in pressure may occur before, during
(simultaneously with) or after the energized fluid composition is
contacted with the subterranean formation. The polymer
solubilization or swelling is achieved by ensuring sufficient
partial pressure of the solubilizing supercritical gas is provided.
In some embodiments, the introduction of an additional gas
component that may not be an acceptable solvent for the polymer
under supercritical conditions may result in a need to increase the
partial pressure of the solubilizing supercritical gas, beyond what
would be needed if a single gas component would be used. Thus, one
having skill in the art would understand that in order to achieve
the polymer solubilization or swelling required for the application
disclosed an "effective partial pressure" of the gas component in
the energized fluid is required. Conversely, in order to de-swell,
of solidity the polymer solution, a reduction in the effective
partial pressure of the gas component in the energized fluid is
required.
[0040] In embodiments, the effective partial pressure of the
supercritical gas in the subterranean formation is reduced by an
amount sufficient to de-swell or solidify the polymer and to form a
polymeric foam structure within the subterranean formation due to
the release of the supercritical solvent in the form of gas. This
polymeric foam structure may be entirely solid or only partially
solid depending upon the amount of pressure reduction. The
polymeric foam structure may also be referred to as a solid
open-cell foam structure. For example, the amount the pressure is
reduced depends upon the gas component. For example, if the gas
component is carbon dioxide, the pressure of the subterranean
formation may be reduced to below about 1000 psi (6894.76 kPa) or
below about 400 psi (2757.90 kPa), such as form example, below
about 350 psi (2413.17 kPa) or below about 300 psi (2068.43 kPa).
The effective partial pressure of the supercritical gas in the
subterranean formation may be reduced by any acceptable method,
such as, for example, decreasing the total wellhead pressure by
manipulating the valves and/or fitting located on top of the well
casing (i.e., Christmas tree) that control the production rate of
hydrocarbon fluid, by introducing a vacuum or a pump, by
introducing into the wellbore a lower density fluid, or by diluting
downhole the solving supercritical gas concentration with a
non-swelling gas.
[0041] As discussed above, a polymeric open cell foams may be
formed downhole in the subterranean formation. Such a foam can be
designed to be capable of sustaining the static closure stress of
some formations, such as, for example, shallow formations, coalbed,
or shale reservoirs, and the like, and therefore be used as a
proppant or proppant less fracturing fluid. Also, such a foam may
be used to fill the space between an open hole and a screen as used
in sand control treatments or to consolidate near wellbore regions
in sanding prone reservoirs. Also such foam may be used to
partially fill the pore space in the near wellbore region of a
formation to consolidate said formation in sanding prone
reservoirs. Also during drilling in situations where mud losses are
found (loss circulation), such foam may be used to partially fill
the void space in the drilled section to prevent further mud
loses.
[0042] Embodiments may also include proppant particles that are
substantially insoluble in the fluids of the formation. Proppant
particles carried by the treatment fluid remain in the fracture
created, or in the wellbore, or in the annular space between a
wellbore and a screen in sand prone formations, thus propping open
the fracture when the fracturing pressure is released and the well
is put into production, or keeping the wellbore face stable when
the well is put into production in sand prone formations. Suitable
proppant materials include, but are not limited to, sand, walnut
shells, sintered bauxite, glass beads, ceramic materials, naturally
occurring materials, or similar materials. Mixtures of proppants
can be used as well. If sand is used, it may be from about 20 to
about 100 U.S. Standard Mesh in size. With synthetic proppants,
mesh sizes about 8 or greater may be used. Naturally occurring
materials may be underived and/or unprocessed naturally occurring
materials, as well as materials based on naturally occurring
materials that have been processed and/or derived. Suitable
examples of naturally occurring particulate materials for use as
proppants include: ground or crushed shells of nuts such as walnut,
coconut, pecan, almond, ivory nut, brazil nut, etc.; ground or
crushed seed shells (including fruit pits) of seeds of fruits such
as plum, olive, peach, cherry, apricot, etc.; ground or crushed
seed shells of other plants such as maize (e.g., corn cobs or corn
kernels), etc.; processed wood materials such as those derived from
woods such as oak, hickory, walnut, poplar, mahogany, etc.
including such woods that have been processed by grinding,
chipping, or other form of particulation, processing, etc. Further
information on nuts and composition thereof may be found in
ENCYCLOPEDIA OF CHEMICAL TECHNOLOGY, Edited by Raymond E. Kirk and
Donald F. Othmer, Third Edition, John Wiley & Sons, vol. 16,
pp. 248-273, (1981).
[0043] The concentration of proppant in the fluid can be any
concentration known in the art. For example, the concentration of
proppant in the fluid may be in the range of from about 0.03 to
about 3 kilograms of proppant added per liter of liquid phase.
Also, any of the proppant particles can further be coated with a
resin to potentially improve the strength, clustering ability, and
flow back properties of the proppant.
[0044] A fiber component may be included in the fluids to achieve a
variety of properties including improving particle suspension, and
particle transport capabilities, and gas phase stability. Fibers
used may be hydrophilic or hydrophobic in nature. Fibers can be any
fibrous material, such as, but not necessarily limited to, natural
organic fibers, comminuted plant materials, synthetic polymer
fibers (by non-limiting example polyester, polyaramide, polyamide,
novoloid or a novoloid-type polymer), fibrillated synthetic organic
fibers, ceramic fibers, inorganic fibers, metal fibers, metal
filaments, carbon fibers, glass fibers, ceramic fibers, natural
polymer fibers, and any mixtures thereof. Particularly useful
fibers are polyester fibers coated to be highly hydrophilic, such
as, but not limited to, DACRON.RTM. polyethylene terephthalate
(PET) Fibers available from Invista Corp. Wichita, Kans., USA,
67220. Other examples of useful fibers include, but are not limited
to, polylactic acid polyester fibers, polyglycolic acid polyester
fibers, polyvinyl alcohol fibers, and the like. When used in
fluids, the fiber component may be included at concentrations from
about 1 to about 15 grams per liter of the liquid phase of the
fluid, such as a concentration of fibers from about 2 to about 12
grams per liter of liquid, or from about 2 to about 10 grams per
liter of liquid.
[0045] Embodiments may further use fluids containing other
additives and chemicals that are known to be commonly used in
oilfield applications by those skilled in the art. These include,
but are not necessarily limited to, materials such as surfactants
in addition to those mentioned hereinabove, breaker aids in
addition to those mentioned hereinabove, oxygen scavengers, alcohol
stabilizers, scale inhibitors, corrosion inhibitors, fluid-loss
additives, bactericides and biocides such as
2,2-dibromo-3-nitrilopropionamine or glutaraldehyde, and the like.
Also, they may include a co-surfactant to optimize viscosity or to
minimize the formation of stable emulsions that contain components
of crude oil.
[0046] As used herein, the term "alcohol stabilizer" is used in
reference to a certain group of organic molecules substantially or
completely soluble in water containing at least one hydroxyl group,
which are susceptible of providing thermal stability and long term
shelf life stability to aqueous zirconium complexes. Examples of
organic molecules referred as "alcohol stabilizers" include but are
not limited to methanol, ethanol, n-propanol, isopropanol,
n-butanol, tert-butanol, ethyleneglycol monomethyl ether, and the
like.
[0047] The energized fluids of the present disclosure may be
suitable for use in numerous subterranean formation types. For
example, formations for which sealing with the energized fluids of
the present disclosure may be used include sand, sandstone, shale,
chalk, limestone, and any other hydrocarbon bearing formation.
[0048] The portion of the wellbore through which the energized is
injected into the treated zone can be open-hole (or comprise no
casing) or can have previously received a casing. If cased, the
casing is desirably perforated prior to injection of the energized
fluid. Optionally, the wellbore can have previously received a
screen. If it has received a screen, the wellbore can also have
previously received a gravel pack, with the placing of the gravel
pack optionally occurring above the formation fracture pressure (a
frac-pack).
[0049] Techniques for injection of fluids with viscosities similar
to those of the energized fluids of the present disclosure are well
known in the art and may be employed with the methods of the
present disclosure. For example, known techniques may be used in
the methods of the present disclosure to convey the energized
fluids of the present disclosure into the subterranean formation to
be treated.
[0050] In embodiments, the energized fluid may be driven into a
wellbore by a pumping system that pumps one or more energized
fluids into the wellbore. The pumping systems may include mixing or
combining devices, wherein various components, such as fluids,
solids, and/or gases may be mixed or combined prior to being pumped
into the wellbore. The mixing or combining device may be controlled
in a number of ways, including, but not limited to, using data
obtained either downhole from the wellbore, surface data, or some
combination thereof. Methods of this disclosure may include using a
surface data acquisition and/or analysis system, such as described
in U.S. Pat. No. 6,498,988, incorporated herein by reference in its
entirety. In embodiments, one or more energized may be pumped into
the wellbore after detecting an unacceptable amount of water or
other condition has been detected. Specific embodiments may
comprise sealing the zone of interest (which may be where an
unacceptable amount of water or other condition has been detected)
using the energized fluid optionally with packers, such as straddle
cup packers. Packers or similar devices can be used to control flow
of the energized fluid into the subterranean formation for which
sealing is desired.
[0051] In embodiments, the energized fluid may be injected into the
subterranean formation at a pressure less than the fracturing
pressure of the formation. For example, the energized fluids will
be injected below the formation fracturing pressure of the
respective formation.
[0052] The volume of energized fluids to be injected into
subterranean formation is a function of the subterranean formation
volume to be treated and the ability of the energized fluid of the
present disclosure to penetrate the subterranean formation. The
volume of energized fluid to be injected can be readily determined
by one of ordinary skill in the art. As a guideline, the formation
volume to be treated relates to the height of the desired treated
zone and the desired depth of penetration. In embodiments, the
depth of penetration of the energized fluid may be at least about
15 cm from the outer wall of the wellbore into the subterranean
formation, such as the depth of penetration of at least about 30 cm
from the outer wall of the wellbore.
[0053] The ability of the energized fluid to penetrate the
subterranean formation depends on the permeability of the
subterranean formation and the viscosity of the energized fluid. In
embodiments, the viscosity of the energized fluid is sufficiently
low as to not slow penetration of the consolidating fluid into the
subterranean formation. In a low-permeability subterranean
formation, the viscosity of the energized fluid is sufficiently low
as to not slow penetration of the consolidating fluid into the
subterranean formation. For example, in a low-permeability
subterranean formation, suitable initial viscosities may be similar
to that of water, such as from about from about 1 cP to about
10,000 cP, or be from about 1 cP to about 1,000 cP, or be from
about 1 cP to about 100 cP at the treating temperature, which may
range from a surface temperature to a bottom-hole static
(reservoir) temperature, such as from about 4.degree. C. to about
80.degree. C., or from about 10.degree. C. to about 70.degree. C.,
or from about 25.degree. C. to about 60.degree. C., or from about
32.degree. C. to about 55.degree. C.
[0054] The above embodiments described for wellbore applications
for various foamed fluids in one or more well service applications
such as, for example, fracturing applications, wellbore
consolidation, and eventually other reservoir optimization
applications like conformance control, water control, or enhanced
oil recovery. In particular, some embodiments are focused upon
polymeric fluids foamed with a gas component that can form a
thermoplastic or thermosetting foam downhole. Moreover, other
embodiments described placing a foamed fluid downhole (in a
fracture, or in a gravel pack) that will, under certain conditions,
allow for sufficient permeability for the hydrocarbon to flow to
the wellbore.
EXAMPLES
Example 1
Formation of Solid Open-Cell Phone with Polyvinyl Acetate
[0055] 10 grams of polyvinyl acetate (PVAc) beads were placed in a
high pressure high temperature (HPHT) apparatus (approximate volume
250 ml), filled with CO.sub.2. The apparatus was brought to a
pressure of 1800 psi (12,410 kPa) and a temperature of 40.degree.
C., therefore placing the CO.sub.2 in a supercritical state. The
CO.sub.2 was then absorbed by the PVAc polymer as evidenced by the
color change from pale to translucent, and then finally to
transparent, thus showing compatibility between the CO.sub.2 and
the polyvinyl acetate.
[0056] The inventor believe that under these conditions, the glass
transition temperature (T.sub.g) of the polyvinyl acetate is
depressed from 30.degree. C. to some lower value by the CO.sub.2,
and the polymer becomes a mobile high viscosity fluid partially
saturated with supercritical CO.sub.2, as shown in the photograph
represented in FIG. 1. As seen in FIG. 1, the HPHT cell has been
rotated onto its side to show the fluid flows under gravity.
[0057] No mixing was applied to the sample in Example 1. Thus, a
two phase system was obtained comprised of high concentration
polymer solution (or plasticized polymer) surrounded by a
supercritical CO.sub.2 (of density 0.7 g/cm.sup.3). The temperature
and pressure were not sufficiently high to obtain a fully miscible
single phase fluid. The pressure of the system was then reduced to
100 psi (10,000 kPa) (similar to what may happen in a downhole
treatment). The CO.sub.2 then reverted into a gas phase, "blowing"
and expanding the polymer, which formed conductive pathways as the
CO.sub.2 exited the solution from the polymer. This resulted in a
solid open-cell foam, as the T.sub.g returned back to 30.degree.
C., as the polymer resolidified, as shown in FIG. 2. We estimated
the volume of the expanded foam to be approximately 5 times that of
the liquid phase.
Example 2
Formation of PVAc Foam with Sand
[0058] Because the present inventors determined that the PVAc foam
possessed good adhesive properties as well as high permeability,
they decided to perform another experiment by adding added loose
sand, (20/40 frac sand) to the polymer/CO.sub.2 mix to determine if
the foam generated would consolidate the sand.
[0059] A blend of 30 g of PVAc beads with 114 g of 20/40 frac sand
was placed into the HPHT cell and heated to 50.degree. C. Then, a
pressure of 1500 psi CO.sub.2 was applied for 45 minutes. The
polyvinyl acetate began to soften and coat the sand when the
pressure of CO.sub.2 approached 900 psi. After 45 minutes, the cell
was slowly de-pressurized. When the pressure of CO.sub.2 dropped to
200 psi, the sand/PVAc blend in the cell began to expand as the
PVAc started to foam. When the HPHT cell was fully depressurized
and dismantled we were left with a block of consolidated sand glued
together by solidified PVAc foam, as shown in FIG. 3. A backflow
experiment with 2 wt % potassium chloride (KCl) brine indicated the
consolidated sand/foam mix had a permeability of approximately 35
Darcy. See FIG. 3.
[0060] This experiment demonstrated that the use of this process
described in application above may be suitable as a downhole
sand-consolidation application and/or an application for binding
proppant within the fractures of a subterranean formation.
Example 3
Formation of PMMA Foam with Sand
[0061] In order to see if we could improve upon the temperature
resistance and stability of the solid polymeric foam we tried a
different polymer,
[0062] 10 grams of polymethyl methacrylate (PMMA) beads supplied by
Sigma Aldrich (having a molecular weight of 15,000 g/mol, a density
of 1.188 g/cm.sup.3 and glass transition temperature (T.sub.g) of
82.degree. C.) were placed in the HPHT apparatus (approximate
volume 250 ml), filled with CO.sub.2. The apparatus was brought to
a pressure of 2000 psi (13790 kPa) and a temperature of 72.degree.
C., therefore placing the CO.sub.2 in a supercritical state.
Similar to PVAc, the PMMA was also partially soluble in
supercritical CO.sub.2, but formed a much more viscous translucent
`blob` of `molten` fluid, as shown below in FIG. 4. The present
inventors observed that the PMMA formed what appeared to be a
two-phase `molten` fluid, with the `upper phase` apparently more
viscous than the `lower phase`. At this stage, the present
inventors believed that this phenomenon may be an effect of
CO.sub.2 extraction on the PMMA and it is simply that one of the
phases, (possibly the lower phase) that is CO.sub.2 rich.
[0063] After a period of 2 hours at pressure and temperature, the
cell was slowly depressurized. As the pressure dropped to 1000 psi
we began to see the first (minor) signs of foaming. This continued
to increase as the pressure was dropped towards ambient and a solid
open-cell expanded foam was formed, as shown in FIG. 5. The PMMA
foam was found to be more brittle and friable than the PVAc foam
and also began to soften at 60.degree. C. So we had made no
improvement to the temperature stability by using this material. We
repeated the experiment with a higher molecular weight PMMA
(MW=350,000), but this made no improvement to the temperature
resistance of the solid foam
[0064] Another experiment was repeated using a 60:40 mix of PMMA
and PVAc, but the results w.r.t temperature stability were the
same.
[0065] Although only a few example embodiments have been described
in detail above, those skilled in the art will readily appreciate
that many modifications are possible in the example embodiments
without materially departing from the above application entitled
"DOWNHOLE POLYMER FOAMS APPLICATIONS". Accordingly, all such
modifications are intended to be included within the scope of this
disclosure as defined in the following claims. In the claims,
means-plus-function clauses are intended to cover the structures
described herein as performing the recited function and not only
structural equivalents, but also equivalent structures. Thus,
although a nail and a screw may not be structural equivalents in
that a nail employs a cylindrical surface to secure wooden parts
together, whereas a screw employs a helical surface, in the
environment of fastening wooden parts, a nail and a screw may be
equivalent structures. It is the express intention of the applicant
not to invoke 35 U.S.C. .sctn.112, paragraph 6 for any limitations
of any of the claims herein, except for those in which the claim
expressly uses the words `means for` together with an associated
function.
* * * * *