U.S. patent application number 12/878450 was filed with the patent office on 2011-06-09 for compositions for stimulating liquid-sensitive subterranean formations.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Matthew E. Blauch, Ottmar F. Hoch, Thomas D. Welton.
Application Number | 20110136703 12/878450 |
Document ID | / |
Family ID | 37890397 |
Filed Date | 2011-06-09 |
United States Patent
Application |
20110136703 |
Kind Code |
A1 |
Hoch; Ottmar F. ; et
al. |
June 9, 2011 |
Compositions for Stimulating Liquid-Sensitive Subterranean
Formations
Abstract
A method comprising: A subterranean formation stimulation fluid
comprising a stimulation gas and a consolidating agent. Suitable
consolidating agents include aqueous tackifying agents, curable
compositions, and noncurable and nonaqueous consolidating
compositions.
Inventors: |
Hoch; Ottmar F.; (Calgary,
CA) ; Blauch; Matthew E.; (Duncan, OK) ;
Welton; Thomas D.; (Duncan, OK) |
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
37890397 |
Appl. No.: |
12/878450 |
Filed: |
September 9, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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11324930 |
Jan 4, 2006 |
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12878450 |
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Current U.S.
Class: |
507/202 |
Current CPC
Class: |
C09K 8/92 20130101; E21B
43/006 20130101; C09K 8/70 20130101; C09K 8/516 20130101; E21B
43/26 20130101 |
Class at
Publication: |
507/202 |
International
Class: |
C09K 8/60 20060101
C09K008/60 |
Claims
1-20. (canceled)
21. A subterranean formation stimulation fluid comprising a
compressible stimulation gas and a consolidating agent wherein the
stimulation fluid comprises a compressible stimulation gas in an
amount of about 80% or more by volume of the stimulation fluid.
22. The stimulation fluid of claim 21 wherein the stimulation fluid
includes at least one additional component chosen from the group
consisting of: a diluting agent, a surfactant, a hydrocarbon
carrier, and a plurality of proppant particulates.
23. The stimulation fluid of claim 21 wherein the compressible
stimulation gas is chosen from the group consisting of: nitrogen,
air, carbon dioxide, propane, or ammonia.
24. The stimulation fluid of claim 21 wherein the consolidating
agent is an aqueous tackifying agent, a curable resin, or a
noncurable and nonaqueous consolidating composition.
25. The stimulation fluid of claim 24 wherein the aqueous
tackifying agent is chosen from the group consisting of: acrylic
acid polymers; acrylic acid ester polymers; acrylic acid derivative
polymers; acrylic acid homopolymers; acrylic acid ester
homopolymers; poly(methyl acrylate); poly (butyl acrylate);
poly(2-ethylhexyl acrylate); acrylic acid ester co-polymers;
methacrylic acid derivative polymers; methacrylic acid
homopolymers; methacrylic acid ester homopolymers; poly(methyl
methacrylate); poly(butyl methacrylate); poly(2-ethylhexyl
methacrylate); acrylamido-methyl-propane sulfonate polymers;
acrylamido-methyl-propane sulfonate derivative polymers;
acrylamido-methyl-propane sulfonate co-polymers; acrylic
acid/acrylamido-methyl-propane sulfonate co-polymers; and
combinations thereof.
26. The stimulation fluid of claim 24 wherein the aqueous
tackifying agent is selected from the group consisting of: benzyl
coco di-(hydroxyethyl) quaternary amine, p-T-amyl-phenol condensed
with formaldehyde; and a copolymer comprising from about 80% to
about 100% C.sub.1-30 alkylmethacrylate monomers and from about 0%
to about 20% hydrophilic monomers.
27. The stimulation fluid of claim 26 wherein the
hydrophilic-monomers are selected from the group consisting of:
dialkyl amino alkyl (meth) acrylates; unsaturated carboxylic acids;
methacrylic acid; acrylic acid; hydroxyethyl acrylate; and
acrylamide.
28. The stimulation fluid of claim 24 wherein the aqueous
tackifying agent is a solution-based polymer having a concentration
of about 20% to about 40%.
29. The stimulation fluid of claim 24 wherein the curable resin
composition is selected from the group consisting of: 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; and mixtures thereof.
30. The stimulation fluid of claim 24 wherein the curable
composition is cured with an internal catalyst, activator, a
time-delayed catalyst, or an external catalyst.
31. The stimulation fluid of claim 24 wherein the curable
composition has a viscosity of about 1 cP to about 100 cP.
32. The stimulation fluid of claim 24 wherein the curable
composition comprises a solvent chosen from the group consisting
of: butyl lactate; butylglycidyl ether; 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; dissolvable
solvents; methanol; isopropanol; butanol; glycol ether solvents;
diethylene glycol methyl ether; dipropylene glycol methyl ether;
2-butoxy ethanol; ethers of a C.sub.2 to C.sub.6 dihydric alkanol
containing at least one C.sub.1 to C.sub.6 alkyl group; mono ethers
of dihydric alkanols; methoxypropanol; butoxyethanol;
hexoxyethanol; isomers thereof; and combinations thereof.
33. The stimulation fluid of claim 24 wherein the noncurable and
nonaqueous consolidating composition is selected from the group
consisting of: condensation reaction products comprised of
polyacids and a polyamine; mixtures of C.sub.36 dibasic acids
containing some trimer and higher oligomers and monomer acids that
are reacted with polyamines; polyacids; trimer acids; synthetic
acids produced from fatty acids; maleic anhydride; acrylic acid;
liquids or solutions of polyesters, polycarbonates, polycarbamates,
or natural resins; silyl-modified polyamides; and combinations
thereof.
34. The stimulation fluid of claim 24 wherein the noncurable and
nonaqueous consolidating composition comprises a multifunctional
material.
35. The stimulation fluid of claim 34 wherein the multifunctional
material is chosen from the group consisting of: aldehydes;
formaldehyde; dialdehydes; glutaraldehyde; hemiacetals; aldehyde
releasing compounds; diacid halides; dihalides; dichlorides;
dibromides; polyacid anhydrides; citric acid; epoxides;
furfuraldehyde; glutaraldehyde; aldehyde condensates; and
combinations thereof.
36. The stimulation fluid of claim 34 wherein the noncurable and
nonaqueous consolidating composition includes a solvent chosen from
the group consisting of: butylglycidyl ether; dipropylene glycol
methyl ether; butyl bottom alcohol; dipropylene glycol dimethyl
ether; diethyleneglycol methyl ether; ethyleneglycol butyl ether;
methanol; butyl alcohol; isopropyl alcohol; diethyleneglycol butyl
ether; propylene carbonate; d-limonene; 2-butoxy ethanol; butyl
acetate; furfuryl acetate; butyl lactate; dimethyl sulfoxide;
dimethyl formamide; fatty acid methyl esters; and combinations
thereof.
37. The stimulation fluid of claim 22 wherein the surfactant is a
cationic surfactant, an anionic surfactant, a nonionic surfactant,
or an amphoteric surfactant.
38. A composition comprising: a compressible stimulation gas, a
hydrocarbon carrier, and a consolidating agent, wherein the
composition is suitable for use as a stimulation fluid in a
subterranean formation and wherein the compressible stimulation gas
is present in the composition in an amount of about 80% or more by
volume of the combination of a compressible stimulation gas, a
hydrocarbon carrier, and a consolidating agent.
39. A subterranean formation stimulation fluid comprising a
compressible stimulation gas and a consolidating agent, wherein the
consolidating agent is present in the stimulation fluid as a
liquid, mist, or a combination of thereof, and wherein the
compressible stimulation gas is present in the stimulation fluid in
an amount of about 80% or more by volume of the stimulation fluid.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present invention is related to co-pending U.S.
application Ser. No. ______ [Attorney Docket No. HES
2004-IP-014007U1] entitled "Methods of Stimulating Liquid-Sensitive
Subterranean Formations," filed concurrently herewith, the entire
disclosure of which is incorporated herein by reference.
BACKGROUND OF THE INVENTION
[0002] The present invention relates to enhancing the permeability
of subterranean formations for the production of hydrocarbons
through stimulation, and more particularly, to stimulation methods
for enhancing the permeability of liquid-sensitive subterranean
formations. "Liquid-sensitive subterranean formations" are those
subterranean formations that are sensitive to liquids (whether
aqueous or hydrocarbon). These formations may form undesirable
precipitates when contacted with an aqueous liquid, for example. In
other instances, for example in a dry CBM well in Canada, the
combination of very low porosity with very low reservoir pressure
may trap an aqueous liquid, i.e., the capillary pressure is higher
than the reservoir pressure so the reservoir pressure cannot expel
the liquid once it gets into the pores of the formation. One type
of liquid-sensitive subterranean formation is a dry coal bed
methane ("CBM") formation. A "dry coal bed methane" formation as
that term is used herein refers to a coal formation that does not
produce an appreciable level of free water. Another example is a
low water content CBM formation. A "low water content CBM"
formation as that term is used herein refers to a CBM formation
that may produce some free water, but not a continuous volume.
Other examples include any formation that can be hydraulically
stimulated where aqueous liquid sensitivity is an issue (e.g.,
shale gas wells with ultra-low permeability, undersaturated or
underpressured reservoirs). An "ultra-low permeability" formation
as that term is used herein refers to a formation having a
permeability of less than 0.1 mD. A "low permeability" formation as
that term is used herein refers to a formation having a
permeability of about 1 mD or less. A dry gas well that can produce
water is an example of a potentially hydrocarbon liquid sensitive
situation because introduction of a hydrocarbon may impact the
relative permeability because the hydrocarbon can act as a trapped
phase in the pore system. Formations that contain a large amount of
organic shales may behave similarly.
[0003] Coal is the most abundant fossil fuel in the world; its
recoverable reserves amount to almost 100 quintillion BTU of
energy, nearly 15 times the total energy content estimated for
known reserves of petroleum. People have mined coal and used it for
heat for centuries. However, relatively recently coal has been
recognized for being the origin and source for coal bed methane
gas, another valuable hydrocarbon fuel. Coal bed methane gas
consists primarily of methane (e.g., 95%) but may also contain
ethane, propane, and higher homologs. At times, the volume of coal
bed methane may be estimated to be about 400 trillion standard
cubic feet (SCF) of gas in place, most of it adsorbed on coal in
seams buried at a depth of less than 9000 feet (ft) from the
surface, and almost half of it is on coal seams buried less than
3000 ft, too deep to mine but easily penetrated by a well bore
using conventional drilling techniques. Coal beds are, therefore,
reservoirs and source rocks for a huge amount of gas that can be
produced, in part, through a well bore. Much research has been
directed to recovering coal bed methane.
[0004] Coal is a dual porosity rock consisting of micropores and a
network of natural fractures known as cleats. The term "cleats" as
used herein with respect to coal seams includes openings or
pathways in the rock that are generally more or less vertical or
transverse to the bedding plane, along which no appreciable
movement between the surfaces of either side of the opening has
occurred. At the time of our discovery, it is believed that the
cleat network and micropores in a coal seam are saturated with
water, and methane is adsorbed to the surface of coal. Reservoir
pressure depletion is a mechanism currently being employed to
desorb methane from coal. When production of coal bed methane is
initiated, water contained in the coal cleat network flows to the
well bore, as per Darcy's Law. This leads to a reduction in
reservoir pressure, which in turn, is thought to desorb methane
from the coal surface. Thus, the gas production rate from a well
may be directly influenced by the speed with which a coal seam is
de-watered. While methane migrates from the coal matrix to the
cleat network by diffusion, the water contained in the coal
micropores (typically 40 Angstrom or smaller pores linked by 5
Angstrom passages) remains essentially immobile due to strong
capillary forces. Thus, even though most of the porosity in coal is
contained within the micropores, the cleat porosity and its
irreducible water saturation are important to a coal bed methane
project. Although the above is the common case with coal
formations, it has been discovered recently (e.g., in western
Canada) that coal systems exist that do not have this mobile water
component. These formations may be especially liquid-sensitive.
[0005] In an effort to enhance porosity within liquid-sensitive
formations such as CBM formations and shale formations, stimulation
processes may be used. Compressible gas streams (such as nitrogen)
often are used in these stimulation processes rather than aqueous
fracturing fluids due to the liquid sensitivity of the formations.
A compressible gas hydraulic fracturing process is a stimulation
technique which provides the parting energy to break up the natural
planes of weakness within the formation rock; a gas squeeze is a
technique to impart nitrogen into the formation rock planar
structure to expand or otherwise enhance pathways therein. A
typical stimulation process usually involves injecting a
compressible gas at a high rate and pressure for a short period of
time (e.g., minutes vs. hours) into a zone of the formation. "Zone"
as used herein simply refers to a portion of the formation and does
not imply a particular geological strata or composition. Proppant
particulates are not usually used, at least in part, because
methods of introducing proppants into gas streams are not yet well
developed or in widespread use due to inherent difficulties
associated with carrying proppants in a gas stream. These
techniques aim to enhance or create pathways within the formation
rock through which produced gases may flow. The term "pathway" as
used herein refers to any channel, void, or the like that may exist
in a liquid-sensitive formation or may be created or enhanced in a
subterranean formation through a stimulation technique; no
particular mechanism of forming the pathways is implied by the
term. Examples of pathways include cleat paths, fractures,
microfractures, vertical fractures, horizontal fractures,
shattering fractures, face cleats, butt cleats, bedding planes,
slickensides, sheet pores, and the like.
[0006] In some instances, the bottomhole pumping pressures used may
be two to three times the overburden pressure of the formation. In
shale gas formations, typical bottomhole pressures would be at some
level above the in situ fracturing stress. Additionally, in coal
formations or other thin-bedded formation, each seam or zone
usually is stimulated separately (e.g., with coiled tubing with a
straddle cup packer assembly) from other seams or zones in the
formation. Oftentimes, a coal formation may include up to 30 or
more seams. Similarly formations with horizontal or deviated well
bores through them may be stimulated at specific intervals to
enhance gas production along the length of the well bore in contact
with the formations. Additionally, these stimulation techniques
pressurize and then depressurize the rock in the formation. Upon
depressurization, shattering of the rock occurs, which is thought
to enhance the desorption of the gas from the matrix. This may
enhance diffusivity in addition to permeability.
[0007] Hydraulic fracturing of liquid sensitive formations without
proppant relies on the rock to "self-prop" (meaning that the
surface roughness of each rock face is such that when the fracture
closes there is sufficient roughness to allow some conductivity in
the fracture face, i.e., the rocks do not go back to a zero
tolerance plane) or have enhanced permeability by having the cleats
and fracture faces misaligned after the fracture closes. If the
rock is soft, these sorts of pathways may not stay open to a
sufficient degree. This may be because the fracture faces are not
well misaligned, or the fracture face may plug with fines.
Additionally, fines may be produced by the fracturing process and
any subsequent in situ stress-induced fines generation (e.g.,
spalling), which can plug any pathways that might otherwise aid
production. As a result of, inter alia, this fines migration and
rock slippage, the productivity of the hydraulically fractured zone
may be reduced significantly.
SUMMARY OF THE INVENTION
[0008] The present invention relates to enhancing the permeability
of subterranean formations for the production of hydrocarbons
through stimulation, and more particularly, to stimulation methods
for enhancing the permeability of liquid-sensitive subterranean
formations.
[0009] In one embodiment, the present invention provides a method
comprising: providing a stimulation fluid that comprises a
stimulating gas and a consolidating agent; and injecting the
stimulation fluid into a portion of a liquid-sensitive formation at
a pressure sufficient to create or enhance a pathway therein.
[0010] In another embodiment, the present invention provides a
method of stimulating a liquid-sensitive subterranean formation
comprising: providing a stimulation gas; adding a consolidating
agent to the stimulating gas to form a stimulation fluid; and
injecting the stimulation fluid into a liquid-sensitive
subterranean formation.
[0011] In another embodiment, the present invention provides a
method comprising: providing a stimulation fluid that comprises a
stimulating gas and a consolidating agent; and injecting the
stimulation fluid into the formation so as to enhance a pathway
therein.
[0012] In one embodiment, the present invention provides a
subterranean formation stimulation fluid comprising a stimulation
gas and a consolidating agent.
[0013] In another embodiment, the present invention provides a zone
in a liquid-sensitive subterranean formation comprising a pathway
enhanced by a stimulation process comprising a stimulation fluid
that comprises a stimulation gas and a consolidating agent.
[0014] The features and advantages of the present invention will be
apparent to those skilled in the art. While numerous changes may be
made by those skilled in the art, such changes are within the
spirit of the invention.
DESCRIPTION OF PREFERRED EMBODIMENTS
[0015] The present invention relates to enhancing the permeability
of subterranean formations for the production of hydrocarbons
through stimulation, and more particularly, to stimulation methods
for enhancing the permeability of liquid-sensitive subterranean
formations. The methods of the present invention may be especially
useful in CBM formations.
[0016] One of the many advantages of the present invention is that
the stimulation fluids are able to stabilize the formation fines
within the formation that may be problematic. This stabilization is
thought to relatively immobilize the fines, and is often referred
to as "fines control." Fines control is particularly important in
CBM formations given the potential volume of the fines that may be
present in such formations. Another advantage is that the fluids
enhance the stability of any pathways formed as a result of the
stimulation treatment. For instance, the consolidating agent in the
fluids of the present invention may stabilize the enhanced state of
shift of any rocks in a zone in the formation that may have shifted
as a result of a stimulation treatment. Another example is that the
consolidating agent may stabilize fines surrounding any pathways
formed as a result of a stimulation treatment, which maintains
their conductivity.
[0017] The compositions and methods of the present invention are
suitable for any liquid-sensitive formation including, but not
limited to, dry CBM formations, low water content CBM formations,
shale formations, ultra-low permeability formations, naturally
fractured formations, and any formation that has liquid sensitivity
and that can be stimulated. Potential applications include
formations that have a tendency to self-prop as well as those that
contain primarily low-permeability rock. Potential applications
also include formations with extreme water sensitivity. The
resultant enhanced permeability of any wells stimulated according
to the present invention may allow operators to be able to pursue
more marginal wells economically than before. Also, the system is
thought to be nondamaging to formations.
[0018] The stimulation fluids of the present invention for use in a
liquid-sensitive formation comprise a stimulation gas and a
consolidating agent. No particular mechanism of consolidation or
stabilization is implied by the term "consolidating agent." The
consolidating agents may provide adhesive bonding between formation
particulates to alter the distribution of the particulates (e.g.,
fines) within the formation in an effort to reduce their potential
negative impact on permeability and/or fracture conductivity, or
provide adhesive bonding between the pathway faces to enhance the
permeability of the shifted state caused by a stimulation
treatment. In some embodiments, the consolidating agents may cause
formation fines to become involved in collective stabilized masses
and/or stabilize the formation fines in place to prevent their
migration that might negatively impact permeability and/or fracture
conductivity. Optionally, the stimulation fluids may comprise
additional components such as suitable diluting agents,
surfactants, and possibly, proppant particulates, and combinations
thereof.
[0019] Adding a surfactant to a stimulation fluid of the present
invention may be useful, e.g., to enhance the miscibility of the
consolidating agent in the stimulation gas, to enhance the coating
process on to the surfaces of the particulates and rocks in the
formation, to aid in the recovery of any residual liquids in the
formations, etc. Suitable surfactants include those that are
compatible with the stimulation gas, the consolidating agent, or
both. Cationic, anionic, nonionic, or amphoteric surfactants that
may be used in subterranean applications are suitable. The choice
of whether to use a surfactant will be governed at least in part by
the mineralogy of the formation. One of ordinary skill in the art
with the benefit of this disclosure art will recognize the
potential usefulness of surfactants. Particularly useful
surfactants may include the detergents sold under the trademarks
Tween.TM. 20,Tween.TM. 80 (which may be available from unique or at
various locations including Europe and Asia), and the
phenoxypolyethoxyethanols like Triton X-10.TM.. A most preferred
surfactant may be Triton X-100.TM.
(t-octylphenoxypolyethoxyethanol) (which may be available from
Spectrum Chemicals and Laboratory Products, at
www.spectrumchemical.com).
[0020] Whether proppant particulates may be used in conjunction
with a stimulation fluid of the present invention will depend on
whether the fluid can support the proppant and place it into a
pathway created or enhanced in the formation. Usually, such gas
stimulation fluids are not suitable for delivering particulates as
part of the treatment. Generally speaking, however, if possible, it
is usually advantageous to use proppant to prop pathways to
maintain conductivity. However, these potential advantages should
be balanced with the ability of the fluid to carry and place the
proppant within the formation. If used, a wide variety of
particulate materials may be used as proppant in accordance with
the present invention, including, but not limited to, sand;
bauxite; ceramic materials; glass materials; polymer materials;
"TEFLON.TM." (tetrafluoroethylene) materials; ground or crushed nut
shells; ground or crushed seed shells; ground or crushed fruit
pits; processed wood; composite particulates prepared from a binder
with filler particulate including silica, alumina, fumed carbon,
carbon black, graphite, mica, titanium dioxide, meta-silicate,
calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow
glass microspheres, and solid glass; or mixtures thereof.
Low-density proppant particulates may be more suitable than higher
density alternatives. The proppant used may have a particle size in
the range of from about 2 to about 400 mesh, U.S. Sieve Series.
Preferably, the proppant is graded sand having a particle size in
the range of from about 10 to about 70 mesh, U.S. Sieve Series.
Preferred sand particle size distribution ranges are one or more of
10/20 mesh, 20/40 mesh, 30/50 mesh, 40/60 mesh, or 50/70 mesh,
depending on the particle size and distribution of the formation
particulates to be screened out by the proppant. 100 mesh to 50
mesh may be preferred in some shale and CBM formations. Smaller
proppants are preferred generally as larger proppants may tend to
pack off pathways, which may be undesirable.
1. Suitable Stimulation Gases
[0021] Any stimulation gas that is suitable for use in stimulation
methods in subterranean formations may be used in the stimulation
fluids of the present invention. Examples include nitrogen, air,
carbon dioxide, propane, ammonia, and the like, and combinations
thereof. Dry nitrogen is preferred. As recognized by one skilled in
the art, some gases may present different or more cumbersome
handling concerns than others, and those concerns should be taken
into account when performing a stimulation method of the present
invention. For instance, carbon dioxide and propane are normally
liquids when pumped, and then they tend to gasify downhole. A
preferred gas is nitrogen because, inter alia, it is usually less
expensive than other options. In a preferred embodiment of the
methods of the invention, the nitrogen is pumped as a liquid, and
heated to form a gas as it is being pumped. A sufficient rate and
amount of the stimulation gas should be present in a stimulation
fluid of the present invention to pressurize the formation. In some
embodiments, this may be from about 2,000 to about 3,000 standard
cubic meters of gas per meter of zone thickness at a rate ranging
from about 500 standard cubic meters per minute per meter of zone
thickness up to about 2000 standard cubic meters per minute.
[0022] In some embodiments, a hydrocarbon carrier that is miscible
or soluble in the stimulation gas may be added. Examples include
liquid propane, liquefied natural gas, liquefied hydrocarbon gases,
gas condensates with carbon chain lengths ranging from C.sub.8 to
C.sub.10, methane, and the like, and combinations and derivatives
thereof. Such a carrier may be useful to carry proppant or add the
consolidating agent to the hydrocarbon carrier. A hydrocarbon
carrier may be advantageously employed in an amount from about 0.1%
to about 70% by volume of the stimulation fluid in some
embodiments. A preferred range may be from about 0.1% to about
10%.
2. Suitable Consolidating Agents
[0023] Suitable consolidating agents include aqueous tackifying
agents, curable compositions, and noncurable and nonaqueous
consolidating compositions. The choice of which to use will be
guided by environmental considerations, handling concerns, clean-up
concerns, and the like. In most instances, aqueous tackifying
agents are preferred. However, if there are sufficient concerns
that the formation cannot handle the aqueous tackifying agents,
then other consolidating agents may be more appropriate. One of
ordinary skill in the art with the benefit of this disclosure will
recognize which consolidating agent may be most suited for a given
application. Some advantages associated with using the aqueous
tackifying agents include: desirable environmental considerations;
ease of application and use; and the nonhardening nature of the
aqueous tackifying agents in that they do not become brittle but
rather remain tacky in the formation. Curable compositions may aid
soft formations in hardening the planar rock face surfaces to
enhance the self propping effects and prevent embedment or loss of
flow capacity or fracture conductivity.
[0024] a. Aqueous Tackifying Agents
[0025] Suitable aqueous tackifying agents generally include charged
polymers that comprise compounds that, when in an aqueous solvent
or solution, will form a non-hardening coating (by themselves or
optionally with an activator).
[0026] Examples of aqueous tackifying agents suitable for use in
the present invention include, but are not limited to, acrylic acid
polymers, acrylic acid ester polymers, acrylic acid derivative
polymers, acrylic acid homopolymers, acrylic acid ester
homopolymers (such as poly(methyl acrylate), poly (butyl acrylate),
and poly(2-ethylhexyl acrylate)), acrylic acid ester co-polymers,
methacrylic acid derivative polymers, methacrylic acid
homopolymers, methacrylic acid ester homopolymers (such as
poly(methyl methacrylate), poly(butyl methacrylate), and
poly(2-ethylhexyl methacryate)), acrylamido-methyl-propane
sulfonate polymers, acrylamido-methyl-propane sulfonate derivative
polymers, acrylamido-methyl-propane sulfonate co-polymers, and
acrylic acid/acrylamido-methyl-propane sulfonate co-polymers, and
combinations thereof. Methods of determining suitable aqueous
tackifying agents and additional disclosure on aqueous tackifying
agents can be found in U.S. patent application Ser. No. 10/864,061,
filed Jun. 9, 2004, and U.S. patent application Ser. No.
10/864,618, filed Jun. 9, 2004, the relevant disclosures of which
are hereby incorporated by reference.
[0027] Some suitable tackifying agents are described in U.S. Pat.
No. 5,249,627 by Harms, et al., the relevant disclosure of which is
incorporated by reference. Harms discloses aqueous tackifying
agents that comprise at least one member selected from the group
consisting of benzyl coco di-(hydroxyethyl) quaternary amine,
p-T-amyl-phenol condensed with formaldehyde, and a copolymer
comprising from about 80% to about 100% C.sub.1-30
alkylmethacrylate monomers and from about 0% to about 20%
hydrophilic monomers. In some embodiments, the aqueous tackifying
agent may comprise a copolymer that comprises from about 90% to
about 99.5% 2-ethylhexylacrylate and from about 0.5% to about 10%
acrylic acid. Suitable hydrophillic monomers may be any monomer
that will provide polar oxygen-containing or nitrogen-containing
groups. Suitable hydrophillic monomers include dialkyl amino alkyl
(meth) acrylates and their quaternary addition and acid salts,
acrylamide, N-(dialkyl amino alkyl) acrylamide, methacrylamides and
their quaternary addition and acid salts, hydroxy alkyl
(meth)acrylates, unsaturated carboxylic acids such as methacrylic
acid or preferably acrylic acid, hydroxyethyl acrylate, acrylamide,
and the like. These copolymers can be made by any suitable emulsion
polymerization technique. Methods of producing these copolymers are
disclosed, for example, in U.S. Pat. No. 4,670,501, the relevant
disclosure of which is incorporated herein by reference.
[0028] Typically, most suitable aqueous tackifying agents are
solution-based polymers; they are usually available in about 20% to
40% concentrations. In some embodiments, the aqueous tackifying
agent is about a 40% solution in water, with possibly other small
amounts of surfactants or other additives being present. One
skilled in the art with the benefit of this disclosure will
envision readily dried polymer compositions as well as diluted
compositions (e.g., polymer concentrations of less than about
20%).
[0029] In some instances, an activator for the aqueous tackifying
agent may be useful, for example, where the stimulating gas is not
dry. Acids such as acetic acid are examples of suitable activators.
Delayed release acids may also be suitable activators. These may
include acid precursors, and encapsulated acids.
[0030] b. Curable Compositions
[0031] The curable compositions suitable for use in the methods of
the present invention comprise a resin and a solvent. "Resin" as
used herein refers to any of numerous physically similar
polymerized synthetics or chemically modified natural resins
including thermoplastic materials and thermosetting materials. One
should note that the choice of solvent can be made so as to not be
problematic for the liquid-sensitive formations.
[0032] Resins suitable for use in the curable compositions of the
present invention include all resins known in the art that are
capable of consolidating formation fines into a stabilized mass or
stabilizing the rock faces within the formation. Many such resins
are commonly used in subterranean consolidation operations, and
some suitable resins include: 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; and mixtures 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.
[0033] The curable compositions suitable for use in the methods of
the present invention preferably have a viscosity of about 1 cP to
about 100 cP, more preferably a viscosity of 20 cP or less, and
most preferably a viscosity of 10 cP or less. Although these
compositions are especially preferred for use in the methods of the
present invention due to, inter alia, pumping considerations, the
formation conditions, viscosity, cost, and safety issues, any
suitable resin should work.
[0034] 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
40.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.
[0035] Solvents may be useful. Any solvent that is compatible with
the chosen resin and achieves the desired viscosity effect is
suitable for use in the curable compositions. Some preferred
solvents are those having lower flash points to enhance miscibility
with the produced gas. Such solvents include butyl lactate,
butylglycidyl ether, 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 preferred
solvents include aqueous dissolvable solvents such as, methanol,
isopropanol, butanol, 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 C.sub.2 to C.sub.6
dihydric alkanol containing at least one C.sub.1 to C.sub.6 alkyl
group, mono ethers of dihydric alkanols, methoxypropanol,
butoxyethanol, hexoxyethanol, and isomers thereof. Selection of an
appropriate solvent is dependent on the resin chosen and is within
the ability of one skilled in the art with the benefit of this
disclosure.
[0036] c. Noncurable and Nonaqueous Consolidating Compositions
[0037] One type of noncurable and nonaqueous consolidating
composition suitable for use in the present invention comprises
polyamides that are liquids or in solution at the temperature of
the subterranean formation such that they are, by themselves,
non-hardening when introduced into the subterranean formation. A
particularly preferred product is a condensation reaction product
comprised of commercially available polyacids and a polyamine. Such
commercial products include compounds such as mixtures of C.sub.36
dibasic acids containing some trimer and higher oligomers and also
small amounts of monomer acids that are reacted with polyamines.
Other polyacids include trimer acids, synthetic acids produced from
fatty acids, maleic anhydride, acrylic acid, and the like. Such
acid compounds are commercially available from companies such as
Witco Corporation, Union Camp, Chemtall, and Emery Industries. The
reaction products are available from, for example, Champion
Technologies, Inc. and Witco Corporation. Additional compounds
which may be used as noncurable and nonaqueous consolidating
compositions include liquids and solutions of, for example,
polyesters, polycarbonates and polycarbamates, natural resins such
as shellac, and the like. Other suitable noncurable and nonaqueous
consolidating compositions are described in U.S. Pat. No. 5,853,048
issued to Weaver, et al. and U.S. Pat. No. 5,833,000 issued to
Weaver, et al., the relevant disclosures of which are herein
incorporated by reference.
[0038] Noncurable and nonaqueous consolidating compositions
suitable for use in the present invention may be either used such
that they form a non-hardening coating or they may be combined with
a multifunctional material capable of reacting with the noncurable
compositions to form a hardened coating downhole. A "hardened
coating" as used herein means that the reaction of the tackifying
compound with the multifunctional material will result in a
substantially non-flowable reaction product that exhibits a higher
compressive strength in a consolidated agglomerate than the
tackifying compound alone. In this instance, the noncurable and
nonaqueous consolidating compositions may function similarly to a
hardenable resin. Multifunctional materials suitable for use in the
present invention include, but are not limited to, aldehydes such
as formaldehyde, dialdehydes such as glutaraldehyde, hemiacetals or
aldehyde releasing compounds, diacid halides, dihalides such as
dichlorides and dibromides, polyacid anhydrides such as citric
acid, epoxides, furfuraldehyde, glutaraldehyde or aldehyde
condensates and the like, and combinations thereof. In some
embodiments of the present invention, the multifunctional material
may be mixed with the tackifying compound in an amount of from
about 0.01% to about 50% by weight of the tackifying compound to
effect formation of the reaction product. In some preferable
embodiments, the compound is present in an amount of from about
0.5% to about 1% by weight of the tackifying compound. Suitable
multifunctional materials are described in U.S. Pat. No. 5,839,510
issued to Weaver, et al., the relevant disclosure of which is
herein incorporated by reference.
[0039] Solvents suitable for use with the noncurable and nonaqueous
consolidating compositions include any solvent that is compatible
with a particular or chosen noncurable and nonaqueous consolidating
composition, and achieves the desired viscosity effect. The
solvents that can be used in the present invention preferably
include those having high flash points (most preferably above about
125.degree. F.). Examples of solvents suitable for use in the
present invention include, but are not limited to, butylglycidyl
ether, dipropylene glycol methyl ether, butyl bottom alcohol,
dipropylene glycol dimethyl ether, diethyleneglycol methyl ether,
ethyleneglycol butyl ether, methanol, butyl alcohol, isopropyl
alcohol, diethyleneglycol butyl ether, propylene carbonate,
d-limonene, 2-butoxy ethanol, butyl acetate, furfuryl acetate,
butyl lactate, dimethyl sulfoxide, dimethyl formamide, fatty acid
methyl esters, and combinations thereof. It is within the ability
of one skilled in the art, with the benefit of this disclosure, to
determine whether a solvent is needed to achieve a viscosity
suitable to the subterranean conditions and, if so, how much.
[0040] Optionally, silyl-modified polyamide compounds may be used
in the methods of the present invention as noncurable and
nonaqueous consolidating compositions, and may be described as
substantially self-hardening compositions that are capable of at
least partially adhering to formation fines 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, formation
pathway faces. Such silyl-modified polyamides may be based, for
example, on the reaction product of a silating compound with a
polyamide or a mixture of polyamides. The polyamide or mixture 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 issued to
Matherly, et al., the relevant disclosure of which is herein
incorporated by reference.
[0041] In preferred embodiments, the consolidating agents may be
introduced to the stimulation gas as a liquid or mist on-the-fly. A
high pressure chemical injection pump or low-rate fluid pumper may
be used. In an example of such an embodiment, the mist would
comprise a low concentration of a suitable consolidating agent,
generally from about 0.01% to about 100% (e.g., in a slug
application) of the volume of a stimulation fluid at in-situ
treatment volume. In preferred embodiments, the amount may be up to
about 20%.
[0042] In one embodiment, the present invention provides a method
that comprises the steps of: providing a stimulation fluid that
comprises a stimulation gas and a consolidating agent; and
injecting the stimulation fluid into a portion of an
liquid-sensitive formation at a pressure sufficient to create or
enhance a pathway therein. Existing coiled tubing technology with
existing dual-cup packers may be used in such a method. In some
embodiments, the pressure used may be up to about 4 times the
fracture gradient. Generally speaking, at least in some instances,
the pressure limit may be that pressure which is equal to or
greater than the overburden pressure.
[0043] To facilitate a better understanding of the present
invention, the following examples of certain aspects of some
embodiments are given. In no way should the following examples be
read to limit, or define, the scope of the invention.
EXAMPLES
Example 1-Consolidating Agent With Coal
[0044] Description of Experiment: 25 grams of coal obtained from a
coal mine in Utah were lightly disarticulated using a mortar and
pestle to obtain a wide distribution of angular coal cleat blocks
ranging from approximately two centimeters down to dust particle
size. The disarticulated coal was then placed into a 5 inch square
"weigh boat" (Fisherbrand Polystyrene Anti-Static Weighing Dishes),
and sprayed with a concentrated aqueous tackifying agent as
described herein. The amount of the aqueous tackifying agent
sprayed was sufficient to lightly coat the coal particles without
pooling or running of liquid from the surfaces. A stream of air was
then applied across the particles.
[0045] Observations: Upon application of an air stream, no airborne
particles were observed in the air stream. All coal particles
appeared to be bonded to the larger coal surfaces, which we believe
rendered the smaller particles immobile in the gas stream. Upon
further air drying for approximately 15 minutes, the aggregate of
coal was sufficiently tackified to enable the inversion of the
weight boat to a vertical position without the significant loss or
"dumping" of particles from the container, which we believe
indicated particle to particle adhesion sufficient to affect angle
of repose. Smaller particles were found to be well adhered to the
larger particles and the weigh boat surface.
Example 2-Well Application
[0046] In a prophetic application on a well, the outlet of a
high-pressure chemical injection pump would be connected to a high
pressure nitrogen pump line, which in turn would be connected from
high-rate, high-pressure nitrogen pump to a well's tubing. The
nitrogen would be pumped at 1300 scm/min for 2000 scm for a 1-metre
thick coal zone. This is equivalent to 25 m.sup.3 nitrogen volume
at a bottomhole treatment pressure of 8 MPa. For a total 1.54
minutes of pumping time, the aqueous tackifying agent would be
pumped at 65 L/min for the first 0.62 minutes. Thus 40 litres of
aqueous tackifying agent should form a mist with the first 10
m.sup.3 of the total 25 m.sup.3 of treatment volume. The nitrogen
used for the treatment would be a dessicated anhydrous nitrogen
stream.
[0047] The features and advantages of the present invention will be
readily apparent to those skilled in the art. While numerous
changes may be made by those skilled in the art, such changes are
within the spirit of the invention.
* * * * *
References