U.S. patent application number 13/462307 was filed with the patent office on 2013-11-07 for methods for controlling formation fines migration.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is Philip D. Nguyen, Richard D. Rickman. Invention is credited to Philip D. Nguyen, Richard D. Rickman.
Application Number | 20130292116 13/462307 |
Document ID | / |
Family ID | 49511671 |
Filed Date | 2013-11-07 |
United States Patent
Application |
20130292116 |
Kind Code |
A1 |
Nguyen; Philip D. ; et
al. |
November 7, 2013 |
Methods for Controlling Formation Fines Migration
Abstract
Generally, a consolidating treatment fluid includes at least an
aqueous base fluid and an ultra-dilute water-based curable resin.
The consolidating treatment fluid may be used in a plurality of
subterranean operations to consolidate the unconsolidated particles
within the subterranean formation.
Inventors: |
Nguyen; Philip D.; (Duncan,
OK) ; Rickman; Richard D.; (Duncan, OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Nguyen; Philip D.
Rickman; Richard D. |
Duncan
Duncan |
OK
OK |
US
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
49511671 |
Appl. No.: |
13/462307 |
Filed: |
May 2, 2012 |
Current U.S.
Class: |
166/276 |
Current CPC
Class: |
C09K 8/508 20130101;
C09K 8/5751 20130101; C09K 8/68 20130101; C09K 8/703 20130101; C09K
8/76 20130101; C09K 8/516 20130101; C09K 8/035 20130101 |
Class at
Publication: |
166/276 |
International
Class: |
E21B 43/02 20060101
E21B043/02 |
Claims
1. A method comprising: providing a consolidating treatment fluid
that comprises an aqueous base fluid and a water-based curable
resin at about 0.01% to about 3% by weight of the aqueous base
fluid; introducing the consolidating treatment fluid into at least
a portion of a subterranean formation comprising unconsolidated
formation fines; and allowing the resin to cure so as to
consolidate the unconsolidated formation fines.
2. The method of claim 1, wherein the water-based curable resin
comprises at least one selected from the group consisting of an
epoxy-based resin, a novolak resin, a polyepoxide resin, a
phenol-aldehyde resin, a urea-aldehyde resin, a urethane resin, a
phenolic resin, a furan resin, a furan/furfuryl alcohol resin, a
phenolic/latex resin, a phenol formaldehyde resin, a polyester
resin and hybrids and copolymers thereof, a polyurethane resin and
hybrids and copolymers thereof, an acrylate resin, and any
combination thereof.
3. The method of claim 1, wherein the water-based curable resin
comprises a two-component epoxy-based resin at about 0.01% to about
3% by weight of the aqueous base fluid, an amine-based curing agent
at about 0.01% to about 3% by weight of the aqueous base fluid, and
a silane coupling agent at about 0.01% to about 2% by weight of the
aqueous base fluid.
4. The method of claim 1, wherein the consolidating treatment fluid
is foamed.
5. The method of claim 1, wherein the consolidating treatment fluid
further comprises a clay stabilizing agent.
6. The method of claim 1, wherein the consolidating treatment fluid
further comprises at least one additive selected from the group
consisting of a salt, a weighting agent, an inert solid, a fluid
loss control agent, an emulsifier, a dispersion aid, a corrosion
inhibitor, an emulsion thinner, an emulsion thickener, a
viscosifying agent, a gelling agent, a surfactant, a particulate, a
proppant, a gravel particulate, a lost circulation material, a pH
control additive, a breaker, a biocide, a crosslinker, a
stabilizer, a chelating agent, a scale inhibitor, a gas hydrate
inhibitor, a mutual solvent, an oxidizer, a reducer, a friction
reducer, a clay stabilizing agent, or any combination thereof.
7. The method of claim 1, wherein introducing the consolidating
treatment fluid is at matrix flow rate.
8. The method of claim 1 further comprising: introducing a preflush
treatment fluid prior to introduction of the consolidating
treatment fluid, wherein the preflush treatment fluid comprises a
second aqueous base fluid.
9. The method of claim 1 further comprising: producing hydrocarbons
is from a production wellbore; and wherein introducing the
consolidating treatment fluid is through an injection wellbore.
10. A method comprising, in order: introducing a preflush treatment
fluid into at least a portion of a subterranean formation
comprising unconsolidated formation fines, the preflush treatment
fluid comprising a first aqueous base fluid; introducing a
consolidating treatment fluid in the portion of the subterranean
formation, the treatment fluid comprising a second aqueous base
fluid and a water-based curable resin at about 0.01% to about 3% by
weight of the second aqueous base fluid; allowing the resin to cure
so as to consolidate the unconsolidated formation fines; and
producing hydrocarbon fluids from the portion of the subterranean
formation.
11. The method of claim 10, wherein the water-based curable resin
comprises at least one selected from the group consisting of an
epoxy-based resin, a novolak resin, a polyepoxide resin, a
phenol-aldehyde resin, a urea-aldehyde resin, a urethane resin, a
phenolic resin, a furan resin, a furan/furfuryl alcohol resin, a
phenolic/latex resin, a phenol formaldehyde resin, a polyester
resin and hybrids and copolymers thereof, a polyurethane resin and
hybrids and copolymers thereof, an acrylate resin, and any
combination thereof.
12. The method of claim 10, wherein the water-based curable resin
comprises a two-component epoxy-based resin at about 0.01% to about
3% by weight of the second aqueous base fluid, an amine-based
curing agent at about 0.01% to about 3% by weight of the second
aqueous base fluid, and a silane coupling agent at about 0.01% to
about 2% by weight of the second aqueous base fluid.
13. The method of claim 10, wherein the consolidating treatment
fluid is foamed.
14. The method of claim 10, wherein the consolidating treatment
fluid further comprises a clay stabilizing agent.
15. The method of claim 10, wherein introducing the consolidating
treatment fluid is at matrix flow rate.
16. A method comprising, in order: introducing a consolidating
treatment fluid in the portion of the subterranean formation, the
treatment fluid comprising an aqueous base fluid, a two-component
epoxy-based resin at about 0.01% to about 3% by weight of the
aqueous base fluid, an amine-based curing agent at about 0.01% to
about 3% by weight of the aqueous base fluid, and a silane coupling
agent at about 0.01% to about 2% by weight of the aqueous base
fluid; allowing the resin to cure so as to consolidate the
unconsolidated formation fines; and producing hydrocarbon fluids
from the portion of the subterranean formation.
17. The method of claim 16, wherein the consolidating treatment
fluid is foamed.
18. The method of claim 16, wherein the consolidating treatment
fluid further comprises a clay stabilizing agent.
19. The method of claim 16, wherein introducing the consolidating
treatment fluid is at matrix flow rate.
20. The method of claim 16, wherein introducing the consolidating
treatment fluid is through an injection wellbore and producing
hydrocarbons is from a production wellbore.
Description
BACKGROUND
[0001] The present invention relates to methods for controlling
formation fines migration.
[0002] Hydrocarbon wells are often at least partially located in
unconsolidated portions of a subterranean formation. As used
herein, the term "unconsolidated portion of a subterranean
formation" is used to mean a portion of a subterranean formation
that comprises loose particulate matter (e.g., particulates of
sandstones, carbonates, limestones, coal beds, shales, diatomites,
and chalks) that can migrate out of the formation with, among other
things, the oil, gas, water, and/or other fluids recovered out of
the well. The particulate material in a relatively unconsolidated
portion of a subterranean formation may be readily entrained by
recovered fluids, for example, those wherein the particulates in
that portion of the subterranean formation are bonded together with
insufficient bond strength to withstand the forces produced by the
production of fluids through those regions of the formation. The
presence of particulate matter, such as sand, in the recovered
fluids is disadvantageous and undesirable in that the particulates
may abrade pumping and other producing equipment and reduce the
fluid production capabilities of certain portions of a subterranean
formation.
[0003] One method used to control loose sands in unconsolidated
portions of subterranean formations involves consolidating the
particulates in the area of interest into hard, permeable masses.
This is usually accomplished by treating the unconsolidated portion
of the formation with treatment fluids comprising consolidating
agents like resins. Generally, the concentration of the resins in
the treatment fluids is relatively high, which leads to
accumulation of the resins near the wellbore.
[0004] However, resin accumulation may hinder the penetration of
additional resin into the subterranean formation, thereby yielding
essentially a near-wellbore treatment that leaves formation fines
further from the wellbore untreated. Additionally, resin
accumulation may lead to plugging of pores and interstitial space
between formation fines once consolidated, which ultimately reduces
the permeability of the subterranean formation.
[0005] When consolidating treatments adversely affect the
permeability of zones in a subterranean formation, remedial
clean-up operations may be necessary. Often clean-up operations
involve chemicals that are less environmentally friendly and more
expensive than the original consolidating agents used.
Additionally, the increased rig-time before production of
hydrocarbons can begin can be very costly. Therefore, methods that
enable deeper penetration so as to consolidate more formation fines
while minimally impacting the permeability of the formation would
be of use to one skilled in the art.
SUMMARY OF THE INVENTION
[0006] The present invention relates to methods for controlling
formation fines migration.
[0007] Some embodiments of the present invention involve
introducing a consolidating treatment fluid into at least a portion
of a subterranean formation comprising unconsolidated formation
fines; and allowing the resin to cure so as to consolidate the
unconsolidated formation fines. Generally, the consolidating
treatment fluid includes at least an aqueous base fluid and a
water-based curable resin at about 0.01% to about 3% by weight of
the aqueous base fluid.
[0008] Other embodiments of the present invention involve
introducing a preflush treatment fluid into at least a portion of a
subterranean formation comprising unconsolidated formation fines,
the preflush treatment fluid comprising a first aqueous base fluid;
introducing a consolidating treatment fluid in the portion of the
subterranean formation; and allowing the resin to cure so as to
consolidate the unconsolidated formation fines; and producing
hydrocarbon fluids from the portion of the subterranean formation.
Generally, the treatment fluid includes at least an aqueous base
fluid, a two-component epoxy-based resin at about 0.01% to about 3%
by weight of the aqueous base fluid, an amine-based curing agent at
about 0.01% to about 3% by weight of the aqueous base fluid, and a
silane coupling agent at about 0.01% to about 2% by weight of the
aqueous base fluid.
[0009] Still other embodiments of the present invention involve
introducing a consolidating treatment fluid in the portion of the
subterranean formation; allowing the resin to cure so as to
consolidate the unconsolidated formation fines; and producing
hydrocarbon fluids from the portion of the subterranean formation.
Generally, the treatment fluid includes at least an aqueous base
fluid, a two-component epoxy-based resin at about 0.01% to about 3%
by weight of the aqueous base fluid, an amine-based curing agent at
about 0.01% to about 3% by weight of the aqueous base fluid, and a
silane coupling agent at about 0.01% to about 2% by weight of the
aqueous base fluid.
[0010] The features and advantages of the present invention will be
readily apparent to those skilled in the art upon a reading of the
description of the preferred embodiments that follows.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] The following figures are included to illustrate certain
aspects of the present invention, and should not be viewed as
exclusive embodiments. The subject matter disclosed is capable of
considerable modifications, alterations, combinations, and
equivalents in form and function, as will occur to those skilled in
the art and having the benefit of this disclosure.
[0012] FIG. 1 illustrates the test cell used for analyzing
consolidation fluid methods.
[0013] FIG. 2 provides an image of consolidated Brazos River sand
fines after application of an ultra-dilute, water-soluble curable
resin.
[0014] FIG. 3 provides an image of consolidated Brazos River sand
fines after application of an ultra-dilute, water-soluble curable
resin.
DETAILED DESCRIPTION
[0015] The present invention relates to methods for controlling
formation fines migration.
[0016] The methods of the present invention may, in some
embodiments, provide for the consolidation of formation fines with
water-based, ultra-dilute curable resins that may penetrate greater
distances from the wellbore. Further, the use of ultra-dilute
curable resins may provide for less accumulation of the resin, so
as to minimize any deleterious effects on permeability of the
subterranean formation. Additionally, the curable nature of the
resins for use in conjunction with the present invention may
advantageously provide better cohesion between formation fines and
adjacent surfaces like other formation fines or faces of the
subterranean formation.
[0017] As a consequence of using curable resins in an ultra-dilute
concentration, the absolute amount of curable resin introduced in
the subterranean formation may be less than is traditionally used,
which may provide cost savings and minimize environmental
impact.
[0018] The methods of the present invention, may in some
embodiments, be advantageously employed in formations having
unconsolidated formation fines. For example, subterranean
formations that may be particularly susceptible to the formation of
particulates include, but are not limited to, sandstones,
carbonates, limestones, coal beds, shales, diatomites, and
chalks.
[0019] It should be noted that when "about" is provided at the
beginning of a numerical list, "about" modifies each number of the
numerical list. It should be noted that in some numerical listings
of ranges, some lower limits listed may be greater than some upper
limits listed. One skilled in the art will recognize that the
selected subset will require the selection of an upper limit in
excess of the selected lower limit.
[0020] Some embodiments of the present invention may involve
consolidating formation fines with a water-based curable resin.
Some embodiments of the present invention may involve introducing a
consolidating treatment fluid into a wellbore penetrating a
subterranean formation. In some embodiments, a consolidating
treatment fluid for use in conjunction with the present invention
may comprise an aqueous base fluid and a water-based curable resin.
In some embodiments, the water-based curable resin may be present
in a consolidating treatment fluid at a concentration ranging from
a lower limit of about 0.01%, 0.05%, or 0.1% by weight of the
aqueous base fluid to an upper limit of about 3%, 1%, or 0.5% by
weight of the aqueous base fluid, wherein the concentration of the
water-based curable resin may range from any lower limit to any
upper limit and encompass any range therebetween.
[0021] The term "resin" as used herein refers to any of numerous
physically similar polymerized synthetics or chemically modified
natural resins including thermoplastic materials and thermosetting
materials. Resins that may be suitable for use in the present
invention may include substantially all water-based resins known
and used in the art. Suitable water-based curable resins for use in
conjunction with the present invention may include, but are not
limited to, epoxy-based resins, novolak resins, polyepoxide resins,
phenol-aldehyde resins, urea-aldehyde resins, urethane resins,
phenolic resins, furan resins, furan/furfuryl alcohol resins,
phenolic/latex resins, phenol formaldehyde resins, polyester resins
and hybrids and copolymers thereof, polyurethane resins and hybrids
and copolymers thereof, acrylate resins, or any combination
thereof. Specific examples of such resins are discussed below. By
way of nonlimiting example a consolidating treatment fluid may
comprise about 0.01% to about 3% w/w epoxy-based resin, about 0.01%
to about 3% w/w amine-based curing agent, about 0.01% to about 2%
w/w silane coupling agent, and about 92% to about 99% aqueous base
fluid.
[0022] Aqueous base fluids suitable for use in conjunction with the
present invention may comprise fresh water, saltwater (e.g., water
containing one or more salts dissolved therein), brine (e.g.,
saturated salt water or produced water), seawater, produced water
(e.g., water produced from a subterranean formation),
aqueous-miscible fluids, or combinations thereof. Generally, the
water may be from any source, provided that it does not contain
components that might adversely affect the stability and/or
performance of the first treatment fluids or second treatment
fluids of the present invention. In certain embodiments, the
density of the aqueous base fluid can be adjusted, among other
purposes, to provide additional particulate transport and
suspension in the treatment fluids used in the methods of the
present invention. In certain embodiments, the pH of the aqueous
base fluid may be adjusted (e.g., by a buffer or other pH adjusting
agent), among other purposes, to activate a crosslinking agent
and/or to reduce the viscosity of the first treatment fluid (e.g.,
activate a breaker, deactivate a crosslinking agent). In these
embodiments, the pH may be adjusted to a specific level, which may
depend on, among other factors, the types of gelling agents, acids,
and other additives included in the treatment fluid. One of
ordinary skill in the art, with the benefit of this disclosure,
will recognize when such density and/or pH adjustments are
appropriate.
[0023] Suitable aqueous-miscible fluids may include, but not be
limited to, alcohols, e.g., methanol, ethanol, n-propanol,
isopropanol, n-butanol, sec-butanol, isobutanol, and t-butanol;
glycerins; glycols, e.g., polyglycols, propylene glycol, and
ethylene glycol; polyglycol amines; polyols; any derivative
thereof; any in combination with salts, e.g., sodium chloride,
calcium chloride, calcium bromide, zinc bromide, potassium
carbonate, sodium formate, potassium formate, cesium formate,
sodium acetate, potassium acetate, calcium acetate, ammonium
acetate, ammonium chloride, ammonium bromide, sodium nitrate,
potassium nitrate, ammonium nitrate, ammonium sulfate, calcium
nitrate, sodium carbonate, and potassium carbonate; any in
combination with an aqueous-based fluid, and any combination
thereof.
[0024] In some embodiments, the aqueous base fluid may be foamed.
In some embodiments a consolidating treatment fluid for use in
conjunction with the present invention may comprise an aqueous base
fluid, a water-based curable resin, a gas, and a foaming agent.
[0025] In some embodiments, the gas is selected from the group
consisting of nitrogen, carbon dioxide, air, methane, helium,
argon, and any combination thereof. One skilled in the art, with
the benefit of this disclosure, should understand the benefit of
each gas. By way of nonlimiting example, carbon dioxide foams may
have deeper well capability than nitrogen foams because carbon
dioxide emulsions have greater density than nitrogen gas foams so
that the surface pumping pressure required to reach a corresponding
depth is lower with carbon dioxide than with nitrogen.
[0026] In some embodiments, the quality of the foamed treatment
fluid may range from a lower limit of about 5%, 10%, 25%, 40%, 50%,
60%, or 70% gas volume to an upper limit of about 95%, 90%, 80%,
75%, 60%, or 50% gas volume, and wherein the quality of the foamed
treatment fluid may range from any lower limit to any upper limit
and encompass any subset therebetween. Most preferably, the foamed
treatment fluid may have a foam quality from about 85% to about
95%, or about 90% to about 95%.
[0027] Suitable foaming agents for use in conjunction with the
present invention may include, but are not limited to, cationic
foaming agents, anionic foaming agents, amphoteric foaming agents,
nonionic foaming agents, or any combination thereof. Nonlimiting
examples of suitable foaming agents may include, but are not
limited to, surfactants like betaines, sulfated or sulfonated
alkoxylates, alkyl quaternary amines, alkoxylated linear alcohols,
alkyl sulfonates, alkyl aryl sulfonates, C10-C20 alkyldiphenyl
ether sulfonates, polyethylene glycols, ethers of alkylated phenol,
sodium dodecylsulfate, alpha olefin sulfonates such as sodium
dodecane sulfonate, trimethyl hexadecyl ammonium bromide, and the
like, any derivative thereof, or any combination thereof. Foaming
agents may be included in foamed treatment fluids at concentrations
ranging typically from about 0.05% to about 2% of the liquid
component by weight (e.g., from about 0.5 to about 20 gallons per
1000 gallons of liquid).
[0028] In some embodiments, a consolidating treatment fluid for use
in conjunction with the present invention may further comprise
additives. Suitable additives for use in conjunction with the
present invention may include, but are not limited to, salts,
weighting agents, inert solids, fluid loss control agents,
emulsifiers, dispersion aids, corrosion inhibitors, emulsion
thinners, emulsion thickeners, viscosifying agents, gelling agents,
surfactants, particulates, proppants, gravel particulates, lost
circulation materials, pH control additives, breakers, biocides,
crosslinkers, stabilizers, chelating agents, scale inhibitors, gas
hydrate inhibitors, mutual solvents, oxidizers, reducers, friction
reducers, clay stabilizing agents, or any combination thereof. One
skilled in the art with the benefit of this disclosure should
understand the appropriate additives and concentrations thereof for
use in conjunction with the present invention to achieve the
desired result and so as to maintain operability of the methods of
the present invention.
[0029] By way of nonlimiting example, the consolidating treatment
fluid for use in conjunction with the present invention may
comprise an aqueous base fluid, a water-based curable resin, and
clay stabilizing agents. Suitable clay stabilizing agents for use
in conjunction with the present invention may include, but are not
limited to, salts, polymers, resins, soluble organic stabilizing
compounds, or any combination thereof. Examples of suitable clay
stabilizing components and mechanisms of stabilization may be found
in U.S. Pat. No. 7,740,071 entitled "Clay Control Additive for
Wellbore Fluids" filed on Jun. 23, 3006, U.S. Pat. No. 5,197,544
entitled "Method for Clay Stabilization with Quaternary Amines"
filed on Dec. 18, 1991, U.S. Pat. No. 4,366,073 entitled "Oil Well
Treating Method and Composition" filed on Feb. 4, 1980, and U.S.
Patent Application Publication Number 2004/0235677 entitled
"Methods and Compositions for Stabilizing Swelling Clays or
Migrating Fines in Formations" filed on May 23, 2003, each of which
is incorporated herein by reference. Stabilizing components may
interact with the surfaces, interlayers, and core of clays and clay
platelets to mitigate or reverse clay hydration and swelling.
[0030] Some embodiments of the present invention may involve
introducing a consolidating treatment fluid into at least a portion
of the subterranean formation comprising unconsolidated formation
fines and allowing the resin to cure so as to consolidate the
unconsolidated formation fines. Some embodiments may further
involve introducing a preflush treatment fluid prior to
introduction of the consolidation treatment fluid. In some
embodiments, a preflush treatment fluid may comprise an aqueous
base fluid. Suitable aqueous base fluids may include, but are not
limited to, those described herein. In some embodiments, the
aqueous base fluids of the preflush treatment fluid and of the
consolidating treatment fluid may be the same or different.
[0031] In some embodiments the preflush treatment fluid and/or the
consolidating treatment fluid may be introduced into the
subterranean formation at matrix flow rate.
[0032] Some embodiments of the present invention may involve
producing hydrocarbon fluids from the portion of the subterranean
formation comprising the portion of the subterranean formation
comprising formation fines consolidated with methods using
water-based curable resins as described herein.
[0033] Some embodiments of the present invention may involve
treating the portion of the subterranean formation comprising
formation particles consolidated with methods using water-based
curable resins as described herein. Suitable treatment operations
may include, but are not limited to, lost circulation operations,
stimulation operations, sand control operations, completion
operations, acidizing operations, scale inhibiting operations,
water-blocking operations, clay stabilizer operations, fracturing
operations, frac-packing operations, gravel packing operations,
wellbore strengthening operations, and sag control operations. The
methods and compositions of the present invention may be used in
full-scale operations or pills. As used herein, a "pill" is a type
of relatively small volume of specially prepared treatment fluid
placed or circulated in the wellbore.
[0034] As stated above, the methods of the present invention may be
employed in any subterranean treatment where unconsolidated
particulates reside in the formation. These unconsolidated
particulates may comprise, among other things, sand, gravel, fines,
and/or proppant particulates within the open space of one or more
fractures in the subterranean formation (e.g., unconsolidated
particulates that form a proppant pack or gravel pack within the
formation). Using the consolidation fluids and methods of the
present invention, the unconsolidated particulates within the
formation may be remedially treated to consolidate the particulates
into a cohesive, consolidated, yet permeable pack and minimize or
reduce their production with production fluids. For example, in
some embodiments, the consolidation fluid, preflush fluid, and/or
post-flush fluid may be applied to remedially treat a gravel pack
or frac-packs that has failed due to screen damage (often caused by
screen erosion) to reduce the production of gravel, proppant, or
formation sand with the production fluid.
[0035] By way of nonlimiting example, some embodiments may involve
fracturing operations that include water-based curable resins as
described herein. For example, some embodiments may involve using a
consolidating treatment fluid as a pad and/or pre-pad fluid by
introducing the consolidating treatment fluid into a subterranean
formation at a pressure sufficient to create or extend at least one
fracture, where the consolidating treatment fluid comprises an
aqueous base fluid and a water-based curable resin, and then
introducing a plurality of proppant particles into the formation so
as to create a proppant pack in the at least one fracture. In some
embodiments, the water curable resin may be allowed to cure before,
during, and/or after introduction of the proppant particles.
[0036] By way of another nonlimiting example, some embodiments of
the present invention may involve remedial operations using
consolidating treatment fluids to treat portions of the
subterranean formation in close proximity to proppant packs and/or
gravel packs. For example, some embodiments of the present
invention may involve introducing a consolidating treatment fluid
comprising an aqueous base fluid and a water-based curable resin
into at least a portion of the subterranean formation in close
proximity to a proppant pack and/or a gravel pack and then allowing
the water-based curable resin to cure so as to consolidate
unconsolidated particles, e.g., formation fines, in close proximity
to the proppant pack and/or gravel pack. Such an operation may
advantageously reduce and/or mitigate plugging of a proppant pack
and/or gravel pack by unconsolidated particles, and consequently
mitigating decreases in hydrocarbon production.
[0037] By way of yet another nonlimiting example, some embodiments
of the present invention may involve gravel packing operations that
include water-based curable resins as described herein. For
example, some embodiments of the present invention may involve
introducing a consolidating treatment fluid comprising an aqueous
base fluid, a water-based curable resin, and a plurality of gravel
particulates into a wellbore so as to place the gravel particulates
in an annulus between a screen and the wellbore, and then allowing
the water-based curable resin to cure thereby yielding consolidated
particles of and/or in close proximity to the gravel pack, e.g., a
consolidated gravel pack and/or consolidated formation fines in
close proximity to the gravel pack.
[0038] By way of another nonlimiting example, some embodiments of
the present invention may involve using a water-based curable resin
as described herein in an injection well operation. Generally,
injection wells are used in conjunction with production wells so as
to maintain reservoir pressure and consequently production levels
through the production well. To maintain reservoir pressure,
injection wells typically push fluid or gases through the
subterranean formation toward the production well. In formations
comprising unconsolidated formation fines, the fluid or gas from
the injection well may carry the unconsolidated formation fines,
which may lead to (1) formation plugging and inefficiency in
pushing the injection fluid or gas through the subterranean
formation and/or (2) the eventual production of formation fines.
Similarly, when proppant packs are reached, the fluid or gas from
the injection well disrupt the proppant pack, plug the proppant
pack with carried formation fines, and/or eventually cause proppant
particles to reach the wellbore of the production well.
Accordingly, some embodiments of the present invention may involve
injecting a consolidating treatment fluid comprising an aqueous
base fluid and a water curable resin into a subterranean formation
through an injection well so as to consolidate particles as the
consolidating treatment fluid moves through the subterranean
formation from the injection well towards a production well.
[0039] In some embodiments, the resin may be emulsified prior to
being suspended or dispersed in the aqueous base fluid.
Furthermore, in some embodiments the resin may be present in the
consolidation fluid without the use of a solvent to alter the
viscosity of the resin. Due to the absence of such a solvent, in
particular embodiments the fluids may exhibit higher flash points
and pose fewer environmental, safety, and/or compatibility concerns
than consolidation fluids comprising a solvent.
[0040] Emulsified resins suitable for use in conjunction with the
present invention may include all resins known in the art that are
capable of forming a hardened, consolidated mass. The resins may
enhance the grain-to-grain contact between the individual
particulates within the formation, helping bring about the
consolidation of the particulates into a cohesive and permeable
mass. Many such resins are commonly used in subterranean
consolidation operations, and some suitable resins may include, but
are not limited to, two-component epoxy-based resins, novolak
resins, polyepoxide resins, phenol-aldehyde resins, urea-aldehyde
resins, urethane resins, phenolic resins, furan resins,
furan/furfuryl alcohol resins, phenolic/latex resins, phenol
formaldehyde resins, polyester resins and hybrids and copolymers
thereof, polyurethane resins and hybrids and copolymers thereof,
acrylate resins, or any combination thereof. Some suitable resins,
such as epoxy resins, may be cured with an internal catalyst or
activator so that when pumped down hole, they may be cured using
only time and temperature. Other suitable resins, such as furan
resins generally require a time-delayed catalyst or an external
catalyst to help activate the polymerization of the resins if the
cure temperature is low (i.e., less than 250.degree. F.), but will
cure under the effect of time and temperature if the formation
temperature is above about 250.degree. F., preferably above about
300.degree. F. It is within the ability of one skilled in the art,
with the benefit of this disclosure, to select a suitable resin for
use in embodiments of the present invention and to determine
whether a catalyst is required to trigger curing.
[0041] Selection of a suitable resin may be affected by the
temperature of the subterranean formation to which the fluid will
be introduced. By way of example, for subterranean formations
having a bottom hole static temperature ("BHST") ranging from about
60.degree. F. to about 250.degree. F., two-component epoxy-based
resins comprising a hardenable resin component and a hardening
agent component containing specific hardening agents may be
preferred. For subterranean formations having a BHST ranging from
about 300.degree. F. to about 600.degree. F., a furan-based resin
may be preferred. For subterranean formations having a BHST ranging
from about 200.degree. F. to about 400.degree. F., either a
phenolic-based resin or a one-component HT epoxy-based resin may be
suitable. For subterranean formations having a BHST of at least
about 175.degree. F., a phenol/phenol formaldehyde/furfuryl alcohol
resin may also be suitable.
[0042] In some embodiments, emulsified resins may be emulsified
prior to being suspended or dispersed in the aqueous base fluid. By
using a resin emulsified prior to being suspended or dispersed in
the aqueous base fluid, particular embodiments of the present
invention may offer the advantage of easier handling and require
less preparation in the field. Examples of suitable emulsifying
agents may include surfactants, proteins, hydrolyzed proteins,
lipids, glycolipids, and nano-sized particulates, such as fumed
silica.
[0043] One type of resin suitable for use in the methods of the
present invention is a two-component epoxy-based resin comprising a
liquid hardenable resin component and a liquid hardening agent
component. The liquid hardenable resin component comprises a
hardenable resin and an optional solvent. The solvent may be added
to the resin to reduce its viscosity for ease of handling, mixing
and transferring. It is within the ability of one skilled in the
art, with the benefit of this disclosure, to determine if and how
much solvent may be needed to achieve a viscosity suitable to the
subterranean conditions. Factors that may affect this decision
include geographic location of the well, the surrounding weather
conditions, and the desired long-term stability of the
consolidating agent. An alternate way to reduce the viscosity of
the hardenable resin is to heat it. The second component is the
liquid hardening agent component, which comprises a hardening
agent, an optional silane coupling agent, a surfactant, an optional
hydrolyzable ester for, among other things, breaking gelled
fracturing fluid films on proppant particulates, and an optional
liquid carrier fluid for, among other things, reducing the
viscosity of the hardening agent component.
[0044] Examples of hardenable resins that can be used in the liquid
hardenable resin component include, but are not limited to, organic
resins such as bisphenol A diglycidyl ether resins, butoxymethyl
butyl glycidyl ether resins, bisphenol A-epichlorohydrin resins,
bisphenol F resins, polyepoxide resins, novolak resins, polyester
resins, phenol-aldehyde resins, urea-aldehyde resins, furan resins,
urethane resins, glycidyl ether resins, other epoxide resins, and
combinations thereof. In some embodiments, the hardenable resin may
comprise a urethane resin. Examples of suitable urethane resins may
comprise a polyisocyanate component and a polyhydroxy component.
Examples of suitable hardenable resins, including urethane resins,
that may be suitable for use in the methods of the present
invention include those described in U.S. Pat. No. 6,582,819
entitled "Low Density Composite Proppant, Filtration Media, Gravel
Packing Media, and Sports Field Media, and Methods of Making and
Using Same" filed on Feb. 1, 2001; U.S. Pat. No. 4,585,064 entitled
"High Strength Particulates" filed on Jul. 2, 1984; U.S. Pat. No.
6,677,426 entitled "Modified Epoxy Resin Composition, Production
Process for the Same and Solvent-Free Coating Comprising the Same"
filed on May 14, 2002; and U.S. Pat. No. 7,153,575 entitled
"Particulate Material having Multiple Curable Coatings and Methods
of Making and Using Same" filed on May 28, 2003, the entire
disclosures of which are herein incorporated by reference.
[0045] The hardenable resin may be included in the liquid
hardenable resin component in an amount in the range of about 5% to
about 100% by weight of the liquid hardenable resin component. It
is within the ability of one skilled in the art, with the benefit
of this disclosure, to determine how much of the liquid hardenable
resin component may be needed to achieve the desired results.
Factors that may affect this decision include which type of liquid
hardenable resin component and liquid hardening agent component are
used.
[0046] Any solvent that is compatible with the hardenable resin and
achieves the desired viscosity effect may be suitable for use in
the liquid hardenable resin component. Suitable solvents may
include butyl lactate, dipropylene glycol methyl ether, dipropylene
glycol dimethyl ether, dimethyl formamide, diethyleneglycol methyl
ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether,
propylene carbonate, methanol, butyl alcohol, d' limonene, fatty
acid methyl esters, and butylglycidyl ether, and combinations
thereof. Other preferred solvents may include aqueous dissolvable
solvents such as, methanol, isopropanol, butanol, and glycol ether
solvents, and combinations thereof. Suitable glycol ether solvents
include, but are not limited to, diethylene glycol methyl ether,
dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C2
to C6 dihydric alkanol containing at least one C1 to C6 alkyl
group, mono ethers of dihydric alkanols, methoxypropanol,
butoxyethanol, and hexoxyethanol, and isomers thereof. Selection of
an appropriate solvent is dependent on the resin composition chosen
and is within the ability of one skilled in the art, with the
benefit of this disclosure.
[0047] As described above, use of a solvent in the liquid
hardenable resin component is optional but may be desirable to
reduce the viscosity of the hardenable resin component for ease of
handling, mixing, and transferring. However, as previously stated,
it may be desirable in some embodiments to not use such a solvent
for environmental or safety reasons. It is within the ability of
one skilled in the art, with the benefit of this disclosure, to
determine if and how much solvent is needed to achieve a suitable
viscosity. In some embodiments, the amount of the solvent used in
the liquid hardenable resin component may be in the range of about
0.1% to about 30% by weight of the liquid hardenable resin
component. Optionally, the liquid hardenable resin component may be
heated to reduce its viscosity, in place of, or in addition to,
using a solvent.
[0048] Examples of the hardening agents that can be used in the
liquid hardening agent component include, but are not limited to,
cyclo-aliphatic amines, such as piperazine, derivatives of
piperazine (e.g., aminoethylpiperazine) and modified piperazines;
aromatic amines, such as methylene dianiline, derivatives of
methylene dianiline and hydrogenated forms, and
4,4'-diaminodiphenyl sulfone; aliphatic amines, such as ethylene
diamine, diethylene triamine, triethylene tetraamine, and
tetraethylene pentaamine; imidazole; pyrazole; pyrazine;
pyrimidine; pyridazine; 1H-indazole; purine; phthalazine;
naphthyridine; quinoxaline; quinazoline; phenazine; imidazolidine;
cinnoline; imidazoline; 1,3,5-triazine; thiazole; pteridine;
indazole; amines; polyamines; amides; polyamides; and
2-ethyl-4-methyl imidazole; and combinations thereof. The chosen
hardening agent often effects the range of temperatures over which
a hardenable resin is able to cure. By way of example, and not of
limitation, in subterranean formations having a temperature of
about 60.degree. F. to about 250.degree. F., amines and
cyclo-aliphatic amines such as piperidine, triethylamine,
tris(dimethylaminomethyl)phenol, and dimethylaminomethyl)phenol may
be preferred. In subterranean formations having higher
temperatures, 4,4'-diaminodiphenyl sulfone may be a suitable
hardening agent. Hardening agents that comprise piperazine or a
derivative of piperazine have been shown capable of curing various
hardenable resins from temperatures as low as about 50.degree. F.
to as high as about 350.degree. F.
[0049] The hardening agent used may be included in the liquid
hardening agent component in an amount sufficient to at least
partially harden the resin composition. In some embodiments of the
present invention, the hardening agent used is included in the
liquid hardening agent component in the range of about 0.1% to
about 95% by weight of the liquid hardening agent component. In
other embodiments, the hardening agent used may be included in the
liquid hardening agent component in an amount of about 15% to about
85% by weight of the liquid hardening agent component. In other
embodiments, the hardening agent used may be included in the liquid
hardening agent component in an amount of about 15% to about 55% by
weight of the liquid hardening agent component.
[0050] In some embodiments, the consolidating agent may comprise a
liquid hardenable resin component emulsified in a liquid hardening
agent component, wherein the liquid hardenable resin component is
the internal phase of the emulsion and the liquid hardening agent
component is the external phase of the emulsion. In other
embodiments, the liquid hardenable resin component may be
emulsified in water and the liquid hardening agent component may be
present in the water. In other embodiments, the liquid hardenable
resin component may be emulsified in water and the liquid hardening
agent component may be provided separately. Similarly, in other
embodiments, both the liquid hardenable resin component and the
liquid hardening agent component may both be emulsified in
water.
[0051] The optional silane coupling agent may be used, among other
things, to act as a mediator to help bond the resin to formation
particulates or proppant particulates. Examples of suitable silane
coupling agents include, but are not limited to,
N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, and
3-glycidoxypropyltrimethoxysilane, and combinations thereof. The
silane coupling agent may be included in the resin component or the
liquid hardening agent component (according to the chemistry of the
particular group as determined by one skilled in the art with the
benefit of this disclosure). In some embodiments of the present
invention, the silane coupling agent used is included in the liquid
hardening agent component in the range of about 0.1% to about 3% by
weight of the liquid hardening agent component.
[0052] Any surfactant compatible with the hardening agent and
capable of facilitating the coating of the resin onto particulates
in the subterranean formation may be used in the liquid hardening
agent component. Such surfactants include, but are not limited to,
an alkyl phosphonate surfactant (e.g., a C12 to C22 alkyl
phosphonate surfactant), an ethoxylated nonyl phenol phosphate
ester, one or more cationic surfactants, and one or more nonionic
surfactants. Combinations of one or more cationic and nonionic
surfactants also may be suitable. Examples of such surfactant
combinations are described in U.S. Pat. No. 6,311,773 entitled
"Resin Composition and Methods of Consolidating Particulate Solids
in Wells With or Without Closure Pressure" filed on Jan. 28, 2000,
the relevant disclosure of which is incorporated herein by
reference. The surfactant or surfactants that may be used are
included in the liquid hardening agent component in an amount in
the range of about 1% to about 10% by weight of the liquid
hardening agent component.
[0053] While not required, examples of hydrolyzable esters that may
be used in the liquid hardening agent component include, but are
not limited to, a combination of dimethylglutarate,
dimethyladipate, dimethylsuccinate; dimethylthiolate; methyl
salicylate; dimethyl salicylate; and dimethylsuccinate; and
combinations thereof. When used, a hydrolyzable ester is included
in the liquid hardening agent component in an amount in the range
of about 0.1% to about 3% by weight of the liquid hardening agent
component. In some embodiments a hydrolyzable ester is included in
the liquid hardening agent component in an amount in the range of
about 1% to about 2.5% by weight of the liquid hardening agent
component.
[0054] Use of a diluent or liquid carrier fluid in the liquid
hardening agent component is optional and may be used to reduce the
viscosity of the liquid hardening agent component for ease of
handling, mixing, and transferring. As previously stated, it may be
desirable in some embodiments to not use such a solvent for
environmental or safety reasons. Any suitable carrier fluid that is
compatible with the liquid hardening agent component and achieves
the desired viscosity effects is suitable for use in the present
invention. Some suitable liquid carrier fluids are those having
high flash points (e.g., about 125.degree. F.) because of, among
other things, environmental and safety concerns; such solvents
include, but are not limited to, butyl lactate, dipropylene glycol
methyl ether, dipropylene glycol dimethyl ether, dimethyl
formamide, diethyleneglycol methyl ether, ethyleneglycol butyl
ether, diethyleneglycol butyl ether, propylene carbonate, methanol,
butyl alcohol, d' limonene, fatty acid methyl esters, and
combinations thereof. Other suitable liquid carrier fluids include
aqueous dissolvable solvents such as, for example, methanol,
isopropanol, butanol, glycol ether solvents, and combinations
thereof. Suitable glycol ether liquid carrier fluids include, but
are not limited to, diethylene glycol methyl ether, dipropylene
glycol methyl ether, 2-butoxy ethanol, ethers of a C2 to C6
dihydric alkanol having at least one C1 to C6 alkyl group, mono
ethers of dihydric alkanols, methoxypropanol, butoxyethanol,
hexoxyethanol, and isomers thereof. Combinations of these may be
suitable as well. Selection of an appropriate liquid carrier fluid
is dependent on, inter alia, the resin composition chosen.
[0055] Other resins suitable for use in the present invention are
furan-based resins. Suitable furan-based resins include, but are
not limited to, furfuryl alcohol resins, furfural resins,
combinations of furfuryl alcohol resins and aldehydes, and a
combination of furan resins and phenolic resins. Of these, furfuryl
alcohol resins may be preferred. A furan-based resin may be
combined with a solvent to control viscosity if desired. Suitable
solvents for use in the furan-based consolidation fluids of the
present invention include, but are not limited to, 2-butoxy
ethanol, butyl lactate, butyl acetate, tetrahydrofurfuryl
methacrylate, tetrahydrofurfuryl acrylate, esters of oxalic, maleic
and succinic acids, and furfuryl acetate. Of these, 2-butoxy
ethanol is preferred. In some embodiments, the furan-based resins
suitable for use in the present invention may be capable of
enduring temperatures well in excess of 350.degree. F. without
degrading. In some embodiments, the furan-based resins suitable for
use in the present invention are capable of enduring temperatures
up to about 700.degree. F. without degrading.
[0056] Optionally, the furan-based resins suitable for use in the
present invention may further comprise a curing agent to facilitate
or accelerate curing of the furan-based resin at lower
temperatures. The presence of a curing agent may be particularly
useful in embodiments where the furan-based resin may be placed
within subterranean formations having temperatures below about
350.degree. F. Examples of suitable curing agents include, but are
not limited to, organic or inorganic acids, such as, inter alia,
maleic acid, fumaric acid, sodium bisulfate, hydrochloric acid,
hydrofluoric acid, acetic acid, formic acid, phosphoric acid,
sulfonic acid, alkyl benzene sulfonic acids such as toluene
sulfonic acid and dodecyl benzene sulfonic acid ("DDBSA"), and
combinations thereof. In those embodiments where a curing agent is
not used, the furan-based resin may cure autocatalytically.
[0057] Still other resins suitable for use in the methods of the
present invention are phenolic-based resins. Suitable
phenolic-based resins include, but are not limited to, terpolymers
of phenol, phenolic formaldehyde resins, and a combination of
phenolic and furan resins. In some embodiments, a combination of
phenolic and furan resins may be preferred. A phenolic-based resin
may be combined with a solvent to control viscosity if desired.
Suitable solvents for use in the present invention include, but are
not limited to butyl acetate, butyl lactate, furfuryl acetate, and
2-butoxy ethanol. Of these, 2-butoxy ethanol may be preferred in
some embodiments.
[0058] Yet another resin-type material suitable for use in the
methods of the present invention is a phenol/phenol
formaldehyde/furfuryl alcohol resin comprising of about 5% to about
30% phenol, of about 40% to about 70% phenol formaldehyde, of about
10% to about 40% furfuryl alcohol, of about 0.1% to about 3% of a
silane coupling agent, and of about 1% to about 15% of a
surfactant. In the phenol/phenol formaldehyde/furfuryl alcohol
resins suitable for use in the methods of the present invention,
suitable silane coupling agents include, but are not limited to,
N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, and
3-glycidoxypropyltrimethoxysilane. Suitable surfactants include,
but are not limited to, an ethoxylated nonyl phenol phosphate
ester, combinations of one or more cationic surfactants, and one or
more nonionic surfactants and an alkyl phosphonate surfactant.
[0059] In some embodiments, resins suitable for use in the
consolidating agent emulsion compositions of the present invention
may optionally comprise filler particles. Suitable filler particles
may include any particle that-does not adversely react with the
other components used in accordance with this invention or with the
subterranean formation. Examples of suitable filler particles
include silica, glass, clay, alumina, fumed silica, carbon black,
graphite, mica, meta-silicate, calcium silicate, calcine, kaoline,
talc, zirconia, titanium dioxide, fly ash, and boron, and
combinations thereof. In some embodiments, the filler particles may
range in size of about 0.01 .mu.m to about 100 .mu.m. As will be
understood by one skilled in the art, particles of smaller average
size may be particularly useful in situations where it is desirable
to obtain high proppant pack permeability (i.e., conductivity),
and/or high consolidation strength. In certain embodiments, the
filler particles may be included in the resin composition in an
amount of about 0.1% to about 70% by weight of the resin
composition. In other embodiments, the filler particles may be
included in the resin composition in an amount of about 0.5% to
about 40% by weight of the resin composition. In some embodiments,
the filler particles may be included in the resin composition in an
amount of about 1% to about 10% by weight of the resin composition.
Some examples of suitable resin compositions comprising filler
particles are described in U.S. Patent Publication No. 2008/0006405
entitled "Methods and Compositions for Enhancing Proppant Pack
Conductivity and Strength" filed on Jul. 6, 2006, the entire
disclosure of which is herein incorporated by reference.
[0060] Silyl-modified polyamide compounds may be described as
substantially self-hardening compositions that are capable of at
least partially adhering to particulates in the unhardened state,
and that are further capable of self-hardening themselves to a
substantially non-tacky state to which individual particulates such
as formation fines will not adhere to, for example, in formation or
proppant pack pore throats. Such silyl-modified polyamides may be
based, for example, on the reaction product of a silating compound
with a polyamide or a combination of polyamides. The polyamide or
combination of polyamides may be one or more polyamide intermediate
compounds obtained, for example, from the reaction of a polyacid
(e.g., diacid or higher) with a polyamine (e.g., diamine or higher)
to form a polyamide polymer with the elimination of water. Other
suitable silyl-modified polyamides and methods of making such
compounds are described in U.S. Pat. No. 6,439,309 entitled
"Compositions and Methods for Controlling Particulate Movement in
Wellbores and Subterranean Formations" filed on Dec. 13, 2000, the
relevant disclosure of which is herein incorporated by
reference.
[0061] To facilitate a better understanding of the present
invention, the following examples of preferred embodiments are
given. In no way should the following examples be read to limit, or
to define, the scope of the invention.
EXAMPLES
[0062] As illustrated in FIG. 1, a cell was assembled with the
following in order from bottom to top: a bottom plunger, an 80-mesh
screen, a 40/60-mesh sand, 60 g of 20/40 Brady sand+20 g of Brazos
River fines, 16/20 mesh lightweight ceramic proppant
(CarboLite.RTM. available from Carbo Ceramics), a 40-mesh screen,
and a top plunger. In the following tests, samples were generally
injected into the cell via the top plunger, allowed to consolidate,
then flushed from the reverse direction (i.e., from the bottom
plunger) such that the effluent was collected and analyzed for the
concentration of solids so as to indicate the efficacy of
consolidation. Further, in the following test, the cell was
maintained at 200.degree. F. with heat tape wrapped around the
exterior of the cell.
[0063] In Test 1, 100 mL of 3% CLA-WEB.RTM. solution (a
water-soluble cationic oligomer, available from Halliburton Energy
Services, Inc.) was passed through to the cell via the top plunger
at 8 mL per minute, followed by 100 mL of PROPSTOP.RTM. ABC
solution (a consolidating agent, available from Halliburton Energy
Services, Inc.) (prepared by diluting 5 mL of PROPSTOP.RTM. ABC in
95 mL of 3% KCl brine). No post-flush was performed. The cell was
then shut-in for 20 hours at 200.degree. F. Then in the reverse
flow direction, i.e., from the bottom plunger, a solution of 3%
CLA-WEB.RTM. was flowed and collected in 100 mL increments at flow
rates of 50, 100, 150, 200, and 300 mL/min. After the reverse flow
procedure, the packed cell was allowed to cool and the Brazos River
sand fines were removed for visual inspection. As shown in FIG. 2,
after removal, the Brazos River sand fines stay in the cylindrical
shape of the cell with only a small percentage of the fines on the
outer surface sloughing off during handling, indicating significant
cohesion and consolidation between particulate grains of sand and
fines.
[0064] In Test 2, 100 mL of 3% CLA-WEB.RTM. solution (a
water-soluble cationic oligomer, available from Halliburton Energy
Services, Inc.) was passed through to the cell via the top plunger
at 8 mL per minute, followed by 100 mL of PROPSTOP.RTM. ABC
solution (a consolidating agent, available from Halliburton Energy
Services, Inc.) (prepared by diluting 5 mL of PROPSTOP.RTM. ABC in
95 mL of 3% KCl brine). No post-flush was performed. The cell was
then shut-in for 96 hours at 200.degree. F. Then in the reverse
flow direction, i.e., from the bottom plunger, a solution of 3%
CLA-WEB.RTM. was flowed and collected in 100 mL increments at flow
rates of 50, 100, 150, 200, and 300 mL/min. After the reverse flow
procedure, the packed cell was allowed to cool and the Brazos River
sand fines were removed for visual inspection. As shown in FIG. 3,
after removal, the Brazos River sand fines stay in the cylindrical
shape of the cell with only a small percentage of the fines on the
outer surface sloughing off during handling, indicating significant
cohesion and consolidation between particulate grains of sand and
fines.
[0065] Test 3 was a control test; i.e., without treatment of the
ultra-low concentration resin treatment. In Test 3, 100 mL of 3%
CLA-WEB.RTM. solution (a water-soluble cationic oligomer, available
from Halliburton Energy Services, Inc.) was passed through to the
cell via the top plunger at 8 mL per minute. No post-flush was
performed. Then in the reverse flow direction, i.e., from the
bottom plunger, a solution of 3% CLA-WEB.RTM. was flowed and
collected in 100 mL increments at flow rates of 50, 100, 150, 200,
and 300 mL/min. After the reverse flow procedure, the packed cell
was allowed to cool and the Brazos River sand fines were removed.
During removal, the Brazos River sand fines fell apart by gravity
after the bottom plunger was removed indicating there was no
attainable cohesion or consolidation between particulate grains of
sand and fines. Visual inspection of the proppant portion showed
that the pore spaces were filled and saturated with Brazos River
sand fines.
[0066] The total suspended solids concentration in the various
effluent samples was determined by EPA method SM 2540-D, results
shown in Table 1 below. Further, visual inspection of the Brazos
River sand fines for Tests 1 and 2, FIGS. 2-3, show the ultra-low
concentration resin treatment consolidates the Brazos River sand
fines.
TABLE-US-00001 TABLE 1 Effluent Total Suspended Solids
Concentration (mg/L) Flow Rate Test 1 Test 2 Test 3 (control) 50
mL/min 31.66 26.01 40 100 mL/min 39.80 23.41 6,443 150 mL/min 71.36
27.00 11,486 200 mL/min 104.06 22.66 6,979 300 mL/min 385.32 25.05
4,702
[0067] This example demonstrates that curable resins at lower
concentrations including those described herein advantageously
provide stronger cohesion between formation fines so as to reduce
the flow back of formation fines during the production of
hydrocarbons from subterranean formations.
[0068] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered, combined,
or modified and all such variations are considered within the scope
and spirit of the present invention. The invention illustratively
disclosed herein suitably may be practiced in the absence of any
element that is not specifically disclosed herein and/or any
optional element disclosed herein. While compositions and methods
are described in terms of "comprising," "containing," or
"including" various components or steps, the compositions and
methods can also "consist essentially of" or "consist of" the
various components and steps. All numbers and ranges disclosed
above may vary by some amount. Whenever a numerical range with a
lower limit and an upper limit is disclosed, any number and any
included range falling within the range is specifically disclosed.
In particular, every range of values (of the form, "from about a to
about b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be
understood to set forth every number and range encompassed within
the broader range of values. Also, the terms in the claims have
their plain, ordinary meaning unless otherwise explicitly and
clearly defined by the patentee. Moreover, the indefinite articles
"a" or "an," as used in the claims, are defined hereinto mean one
or more than one of the element that it introduces. If there is any
conflict in the usages of a word or term in this specification and
one or more patent or other documents that may be incorporated
herein by reference, the definitions that are consistent with this
specification should be adopted.
* * * * *