U.S. patent application number 10/751593 was filed with the patent office on 2005-07-07 for methods of well stimulation and completion.
Invention is credited to Nguyen, Philip D..
Application Number | 20050145385 10/751593 |
Document ID | / |
Family ID | 34711462 |
Filed Date | 2005-07-07 |
United States Patent
Application |
20050145385 |
Kind Code |
A1 |
Nguyen, Philip D. |
July 7, 2005 |
Methods of well stimulation and completion
Abstract
The present invention relates to improved methods for well
stimulation and completion. More particularly, the present
invention relates to methods of stimulating and completing well
bores while controlling formation sand migration and proppant
flowback. One embodiment of the present invention provides a method
of stimulating a formation surrounding a well bore comprising the
steps of: (a) hydraulically fracturing a formation to create or
enhance at least one fracture; (b) placing proppant coated with a
tackifying agent into the far-well bore area of the fracture; and,
(c) placing an agent capable of controlling particulate flowback
into the well bore or near-well bore area of the fracture.
Inventors: |
Nguyen, Philip D.; (Duncan,
OK) |
Correspondence
Address: |
Robert A. Kent
Halliburton Energy Services
2600 S. 2nd Street
Duncan
OK
73536
US
|
Family ID: |
34711462 |
Appl. No.: |
10/751593 |
Filed: |
January 5, 2004 |
Current U.S.
Class: |
166/279 ;
166/280.2; 166/308.1 |
Current CPC
Class: |
C09K 8/685 20130101;
C09K 8/68 20130101; C09K 8/805 20130101 |
Class at
Publication: |
166/279 ;
166/280.2; 166/308.1 |
International
Class: |
A47B 043/00 |
Claims
What is claimed is:
1. A method of stimulating a formation surrounding a well bore
comprising the steps of: a. hydraulically fracturing a formation to
create or enhance at least one fracture; b. placing proppant coated
with a tackifying agent into the far-well bore area of the
fracture; and, c. placing an agent capable of controlling
particulate flowback into the well bore or near-well bore area of
the fracture.
2. The method of claim 1 wherein the tackifying agent comprises a
polyamide, a polyester, a polycarbonate, a polycarbamate, a natural
resin, or a combination thereof.
3. The method of claim 1 wherein the agent capable of controlling
particulate flowback comprises a screen.
4. The method of claim 3 wherein the screen is sized to control the
flowback of the proppant coated with a tackifying agent.
5. The method of claim 1 wherein the agent capable of controlling
particulate flowback comprises proppant coated with curable
resin.
6. The method of claim 5 wherein the resin comprises a hardenable
resin component comprising a hardenable resin and a hardening agent
component comprising a liquid hardening agent, a silane coupling
agent, and a surfactant.
7. The method of claim 5 wherein the resin composition comprises a
furan-based resin comprising furfuryl alcohol, a mixture furfuryl
alcohol with an aldehyde, a mixture of furan resin and phenolic
resin or mixtures thereof.
8. The method of claim 7 further comprising a solvent comprising
2-butoxy ethanol, butyl acetate, furfuryl acetate, or mixtures
thereof.
9. The method of claim 5 wherein the resin composition comprises a
phenolic-based resin comprising terpolymer of phenol, phenolic
formaldehyde resin, a mixture of phenolic and furan resin, or
mixtures thereof.
10. The method of claim 9 wherein the resin composition further
comprises a solvent comprising butyl acetate, butyl lactate,
furfuryl acetate, 2-butoxy ethanol, or mixtures thereof.
11. The method of claim 5 wherein the resin composition comprises a
HT epoxy-based resin comprising bisphenol A-epichlorohydrin resin,
polyepoxide resin, novolac resin, polyester resin, glycidyl ethers,
or mixtures thereof.
12. The method of claim 11 wherein the resin composition further
comprises a solvent comprising dimethyl sulfoxide, dimethyl
formamide, dipropylene glycol methyl ether, dipropylene glycol
dimethyl ether, dimethyl formamide, diethylene glycol methyl ether,
ethylene glycol butyl ether, diethylene glycol butyl ether,
propylene carbonate, d'limonene, fatty acid methyl esters, or
mixtures thereof.
13. The method of claim 5 wherein the resin composition comprises a
phenol/phenol formaldehyde/furfuryl alcohol resin comprising from
about 5% to about 30% phenol, from about 40% to about 70% phenol
formaldehyde, from about 10 to about 40% furfuryl alcohol, from
about 0.1% to about 3% of a silane coupling agent, and from about
1% to about 15% of a surfactant.
14. A method of stimulating a formation surrounding a well bore
comprising the steps of: a. hydraulically fracturing a formation
through a well bore located in a substantially consolidated
subterranean formation such that fractures are formed or enhanced
so as to place the well bore in fluid communication with an
unconsolidated or weakly consolidated zone of the formation; b.
placing proppant coated with a tackifying agent into the far-well
bore area of the fracture; and, c. placing an agent capable of
controlling particulate flowback into the near-well bore area.
15. The method of claim 14 wherein the well bore is a horizontal
well bore or a highly deviated well bore.
16. The method of claim 14 wherein the tackifying agent comprises a
polyamide, a polyester, a polycarbonate, a polycarbamate, a natural
resin, or a combination thereof.
17. The method of claim 14 wherein the agent capable of controlling
particulate flowback comprises a screen.
18. The method of claim 17 wherein the screen is sized to control
the flowback of the proppant coated with a tackifying agent.
19. The method of claim 14 wherein the agent capable of controlling
particulate flowback comprises proppant coated with curable
resin.
20. The method of claim 19 wherein the resin comprises a hardenable
resin component comprising a hardenable resin and a hardening agent
component comprising a liquid hardening agent, a silane coupling
agent, and a surfactant.
21. The method of claim 19 wherein the resin composition comprises
a furan-based resin comprising furfuryl alcohol, a mixture furfuryl
alcohol with an aldehyde, a mixture of furan resin and phenolic
resin or mixtures thereof.
22. The method of claim 21 further comprising a solvent comprising
2-butoxy ethanol, butyl acetate, furfuryl acetate, or mixtures
thereof.
23. The method of claim 19 wherein the resin composition comprises
a phenolic-based resin comprising terpolymer of phenol, phenolic
formaldehyde resin, a mixture of phenolic and furan resin, or
mixtures thereof.
24. The method of claim 23 wherein the resin composition further
comprises a solvent comprising butyl acetate, butyl lactate,
furfuryl acetate, 2-butoxy ethanol, or mixtures thereof.
25. The method of claim 19 wherein the resin composition comprises
a HT epoxy-based resin comprising bisphenol A-epichlorohydrin
resin, polyepoxide resin, novolac resin, polyester resin, glycidyl
ethers, or mixtures thereof.
26. The method of claim 25 wherein the resin composition further
comprises a solvent comprising dimethyl sulfoxide, dimethyl
formamide, dipropylene glycol methyl ether, dipropylene glycol
dimethyl ether, dimethyl formamide, diethylene glycol methyl ether,
ethylene glycol butyl ether, diethylene glycol butyl ether,
propylene carbonate, d'limonene, fatty acid methyl esters, or
mixtures thereof.
27. The method of claim 19 wherein the resin composition comprises
a phenol/phenol formaldehyde/furfuryl alcohol resin comprising from
about 5% to about 30% phenol, from about 40% to about 70% phenol
formaldehyde, from about 10 to about 40% furfuryl alcohol, from
about 0.1% to about 3% of a silane coupling agent, and from about
1% to about 15% of a surfactant.
28. A method of stimulating a formation surrounding a well bore
comprising the steps of: a. hydraulically fracturing a formation to
create or enhance at least one fracture; b. placing proppant coated
with a tackifying agent into the far-well bore area of the
fracture; and, c. placing an agent capable of controlling
particulate flowback into the well bore or near-well bore area of
the fracture.
29. The method of claim 28 wherein the tackifying agent comprises a
polyamide, a polyester, a polycarbonate, a polycarbamate, a natural
resin, or a combination thereof.
30. The method of claim 28 wherein the agent capable of controlling
particulate flowback comprises a screen.
31. The method of claim 30 wherein the screen is sized to control
the flowback of the proppant coated with a tackifying agent.
32. The method of claim 28 wherein the agent capable of controlling
particulate flowback comprises proppant coated with curable
resin.
33. The method of claim 32 wherein the resin comprises a hardenable
resin component comprising a hardenable resin and a hardening agent
component comprising a liquid hardening agent, a silane coupling
agent, and a surfactant.
34. The method of claim 32 wherein the resin composition comprises
a furan-based resin comprising furfuryl alcohol, a mixture furfuryl
alcohol with an aldehyde, a mixture of furan resin and phenolic
resin or mixtures thereof.
35. The method of claim 32 wherein the resin composition comprises
a phenolic-based resin comprising terpolymer of phenol, phenolic
formaldehyde resin, a mixture of phenolic and furan resin, or
mixtures thereof.
36. The method of claim 32 wherein the resin composition comprises
a HT epoxy-based resin comprising bisphenol A-epichlorohydrin
resin, polyepoxide resin, novolac resin, polyester resin, glycidyl
ethers, or mixtures thereof.
37. The method of claim 36 wherein the resin composition further
comprises a solvent comprising dimethyl sulfoxide, dimethyl
formamide, dipropylene glycol methyl ether, dipropylene glycol
dimethyl ether, dimethyl formamide, diethylene glycol methyl ether,
ethylene glycol butyl ether, diethylene glycol butyl ether,
propylene carbonate, d'limonene, fatty acid methyl esters, or
mixtures thereof.
38. The method of claim 32 wherein the resin composition comprises
a phenol/phenol formaldehyde/furfuryl alcohol resin comprising from
about 5% to about 30% phenol, from about 40% to about 70% phenol
formaldehyde, from about 10 to about 40% furfuryl alcohol, from
about 0.1% to about 3% of a silane coupling agent, and from about
1% to about 15% of a surfactant.
39. A method of stimulating a formation surrounding a well bore
comprising the steps of: a. hydraulically fracturing a formation
through a well bore located in a substantially consolidated
subterranean formation such that fractures are formed or enhanced
so as to place the well bore in fluid communication with an
unconsolidated or weakly consolidated zone of the formation; b.
placing proppant coated with a tackifying agent into the far-well
bore area of the fracture; and, c. placing an agent capable of
controlling particulate flowback into the near-well bore area.
40. The method of claim 39 wherein the tackifying agent comprises a
polyamide, a polyester, a polycarbonate, a polycarbamate, a natural
resin, or a combination thereof.
41. The method of claim 39 wherein the agent capable of controlling
particulate flowback comprises a screen.
42. The method of claim 41 wherein the screen is sized to control
the flowback of the proppant coated with a tackifying agent.
43. The method of claim 39 wherein the agent capable of controlling
particulate flowback comprises proppant coated with curable
resin.
44. The method of claim 43 wherein the resin comprises a hardenable
resin component comprising a hardenable resin and a hardening agent
component comprising a liquid hardening agent, a silane coupling
agent, and a surfactant.
45. The method of claim 43 wherein the resin composition comprises
a furan-based resin comprising furfuryl alcohol, a mixture furfuryl
alcohol with an aldehyde, a mixture of furan resin and phenolic
resin or mixtures thereof.
46. The method of claim 43 wherein the resin composition comprises
a phenolic-based resin comprising terpolymer of phenol, phenolic
formaldehyde resin, a mixture of phenolic and furan resin, or
mixtures thereof.
47. The method of claim 43 wherein the resin composition comprises
a HT epoxy-based resin comprising bisphenol A-epichlorohydrin
resin, polyepoxide resin, novolac resin, polyester resin, glycidyl
ethers, or mixtures thereof.
48. The method of claim 47 wherein the resin composition further
comprises a solvent comprising dimethyl sulfoxide, dimethyl
formamide, dipropylene glycol methyl ether, dipropylene glycol
dimethyl ether, dimethyl formamide, diethylene glycol methyl ether,
ethylene glycol butyl ether, diethylene glycol butyl ether,
propylene carbonate, d'limonene, fatty acid methyl esters, or
mixtures thereof.
49. The method of claim 43 wherein the resin composition comprises
a phenol/phenol formaldehyde/furfuryl alcohol resin comprising from
about 5% to about 30% phenol, from about 40% to about 70% phenol
formaldehyde, from about 10 to about 40% furfuryl alcohol, from
about 0.1% to about 3% of a silane coupling agent, and from about
1% to about 15% of a surfactant.
Description
BACKGROUND OF THE INVENTION
[0001] The present invention relates to improved methods for well
stimulation and completion. More particularly, the present
invention relates to methods of stimulating and completing well
bores while controlling formation sand migration and proppant
flowback.
[0002] A subterranean formation may be treated to increase its
permeability by hydraulically fracturing the formation to create or
enhance one or more cracks or "fractures." Such hydraulic
fracturing is usually accomplished by injecting a viscous
fracturing fluid into the subterranean formation at a rate and
pressure sufficient to cause the formation to break down and
produce one or more fractures or enhance one or more natural
fractures. The fracture or fractures may be horizontal or vertical,
with the latter usually predominating, and with the tendency toward
vertical fractures increasing with the depth of the formation being
fractured. The fracturing fluid is generally a highly viscous gel,
emulsion, or foam that comprises a particulate material often
referred to as proppant. In some fracturing operations, commonly
known as "water fracturing" operations, the fracturing fluid
viscosity is somewhat lowered and yet the proppant remains in
suspension because the fracturing fluid is injected into the
formation at a substantially higher velocity. Whether a highly
viscous fluid is used or a less viscous fluid with a higher
velocity, proppant is deposited in the fracture and functions,
inter alia, to hold the fracture open while maintaining channels
through which produced fluids can flow upon completion of the
fracturing treatment.
[0003] To prevent the subsequent flowback of proppant and other
unconsolidated particulates with the produced fluids, a portion of
the proppant introduced into the fractures may be coated with a
hardenable resin composition. When the fracturing fluid, which is
the carrier fluid for the proppant, reverts to a thin fluid, the
resin-coated proppant is deposited in the fracture, and the
fracture closes on the proppant. Such partially closed fractures
apply pressure on the resin-coated proppant particles, causing the
particles to be forced into contact with each other while the resin
composition hardens. The hardening of the resin composition under
pressure brings about the consolidation of the resin-coated
proppant particles into a substantially hard permeable mass having
compressive and tensile strength that hopefully prevents
unconsolidated proppant and formation sand from flowing out of the
fractures with produced fluids.
[0004] Another method of preventing the flowback of proppant and
other unconsolidated particulates involves the use of screen
assemblies. Some of the early screen technology dictated that the
screens had to be small enough to pass through the smallest
diameter of the well bore on the way to its desired placement
location where the diameter of the well bore may actually be
larger. Developments in technology have lead to expandable screens
such that a relatively small size or small diameter screen may be
placed in a desired location along the well bore and then expanded
to accommodate the actual size of the well bore at the point of
placement. Flowback of the proppant or formation fines with
formation fluids is undesirable as it may erode metal equipment,
plug piping and vessels, and cause damage to valves, instruments,
and other production equipment.
[0005] While the hydraulic fracturing techniques discussed above
are commonly used on vertical well bores, they have not been widely
used to stimulate horizontal well bores, particularly those
penetrating hard rock formations such as sandstone, due, inter
alia, to the fact that such formations usually require high
fracturing pressures and result in complex and potentially unstable
fracture geometries. The geometry of fractures caused by hydraulic
pressure in horizontal well bores is primarily dependent on the
formation in situ stresses. In situ stresses may be thought of as
occurring in three orthogonal planes: vertical stress, maximum
horizontal stress, and minimum horizontal stress. When subjected to
hydraulic pressure, fractures, regardless of origin, attempt to
propagate in planes orthogonal to the minimum horizontal stress.
Thus, fracture configuration resulting from hydraulic pressure can
depend on the orientation of the well bore with respect to the
minimum horizontal stress. Two such configurations have been the
subject on interest in the art: longitudinal fractures that
propagate in plane parallel to the well bore axis that are formed
when a horizontal well bore is drilled parallel to the maximum
horizontal stress (as depicted in FIG. 1); and, transverse
fractures that propagate in planes orthogonal to the well bore axis
that are formed when a horizontal well bore is drilled
perpendicular to the maximum horizontal stress (as depicted in FIG.
2). In such formations, it is often necessary to puncture the
formation to direct the fracture geometry.
[0006] The term "vertical well bore" as used herein refers to a
well bore or portion of a well bore that is substantially vertical
or deviated from vertical in an amount up to about 30.degree.. The
term "horizontal well bore" as used herein refers to a well bore or
portion of a well bore that is substantially horizontal or at an
angle from vertical in the range of from about 70.degree. to about
90.degree. or more. The term "highly deviated well bore" as used
herein refers to a well bore or portion of a well bore that is
angled from about 30.degree. to about 70.degree. from vertical.
SUMMARY OF THE INVENTION
[0007] The present invention relates to improved methods for well
stimulation and completion. More particularly, the present
invention relates to methods of stimulating and completing well
bores while controlling formation sand migration and proppant
flowback.
[0008] One embodiment of the present invention provides a method of
stimulating a formation surrounding a well bore comprising the
steps of: (a) hydraulically fracturing a formation to create or
enhance at least one fracture; (b) placing proppant coated with a
tackifying agent into the far-well bore area of the fracture; and,
(c) placing an agent capable of controlling particulate flowback
into the well bore or near-well bore area of the fracture.
[0009] Another embodiment of the present invention provides a
method of stimulating a formation surrounding a well bore
comprising the steps of: (a) hydraulically fracturing a formation
through a well bore located in a substantially consolidated
subterranean formation such that fractures are formed or enhanced
so as to place the well bore in fluid communication with an
unconsolidated or weakly consolidated zone of the formation; (b)
placing proppant coated with a tackifying agent into the far-well
bore area of the fracture; and, (c) placing an agent capable of
controlling particulate flowback into the near-well bore area.
[0010] Other and further features and advantages of the present
invention will be readily apparent to those skilled in the art upon
a reading of the description of preferred embodiments which
follows.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] FIG. 1 illustrates an example of longitudinal fractures
propagated in a plane substantially parallel to the well bore
axis.
[0012] FIG. 2 illustrates an example of transverse fractures
propagated in a plane substantially orthogonal to the well bore
axis.
[0013] FIG. 3 illustrates an example of puncture orientations that
may be used in the methods of the present invention.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0014] The present invention relates to improved methods for well
stimulation and completion. More particularly, the present
invention relates to methods of stimulating and completing well
bores while controlling formation sand migration and proppant
flowback.
[0015] Some embodiments of the present invention provide methods of
stimulating hydrocarbon production and controlling particulate
migration comprising the steps of (1) hydraulically fracturing a
formation, (2) placing proppant coated with a tackifying agent into
the far-well bore area of the fracture and then (3) placing an
agent capable of controlling particulate flowback into the
near-well bore area. The agent capable of controlling particulate
flowback may be either proppant coated with curable resin or screen
sized to control the flowback of the proppant coated with a
tackifying agent in the well bore. Placing proppant coated with
tackifying agent into the far-well bore area acts, inter alia, to
help control the migration of formation sands. Placing either
proppant coated with curable resin in the fracture near the well
bore or placing a screen in the well bore acts, inter alia, to keep
the proppant in place instead of producing it along with the
produced fluids.
[0016] A tackifying agent is a substance that remains sticky rather
than curing over time. Placing proppant coated with a tackifying
agent into the far-well bore area of the fracture will help prevent
formation sand from invading the near-well bore area of the
fracture as the sands become trapped by the sticky character of the
tackifying agent. Compounds suitable for use as a tackifying
compound in the present invention comprise substantially any
compound that, when in liquid form or in a solvent solution, will
form a sticky, non-hardening coating upon a particulate. A
particularly preferred group of tackifying compounds comprise
polyamides that are liquids or in solution at the temperature of
the subterranean formation such that the polyamides are, by
themselves, non-hardening when present on the particulates
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/or 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 and 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 tackifying compounds include liquids and
solutions of, for example, polyesters, polycarbonates and
polycarbamates, natural resins such as shellac and the like.
Suitable tackifying compounds 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 disclosures of which are herein
incorporated by reference.
[0017] Once the proppant coated with tackifying agent is placed in
the far-well bore area of the fracture, proppant coated with resin
may be placed in the near-well bore area. Resin-coated proppant
will cure and harden into a consolidated mass that is capable of
allowing fluid production and yet will provide a barrier to
flowback of the tackyfied proppant, the resin-coated proppant, and
the formation sands.
[0018] Proppant particles used in accordance with the present
invention are generally of a size such that formation particulates
that may migrate with produced fluids are prevented from being
produced from the subterranean zone. Any suitable proppant may be
used, including graded sand, bauxite, ceramic materials, glass
materials, walnut hulls, polymer beads and the like. Generally, the
proppant particles have a size in the range of from about 4 to
about 100 mesh, U.S. sieve series. The proppant coated with
tackifying agent and placed in the far-well bore area may be the
same as or different than the proppant coated with resin and placed
in the near-well bore area.
[0019] Resins suitable for use in the resin slurries in the present
invention include, but are not limited to, two-component
epoxy-based resins, furan-based resins, phenolic-based resins,
high-temperature (HT) epoxy-based resins, and phenol/phenol
formaldehyde/furfuryl alcohol resins.
[0020] Selection of a suitable resin-type coating material 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 also may be suitable.
[0021] One resin suitable for use in the methods of certain
embodiments of the present invention is a two-component epoxy based
resin comprising a hardenable resin component and a hardening agent
component. The hardenable resin component is comprised of 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 whether 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 and the surrounding
environmental conditions. An alternate way to reduce the viscosity
of the liquid hardenable resin is to heat it. This method avoids
the use of a solvent altogether, which may be desirable in some
circumstances. The second component of the two-component epoxy
based resin is the liquid hardening agent component, and it is
comprised of a hardening agent, a silane coupling agent, a
surfactant, an optional hydrolyzable ester for, inter alia,
breaking gelled fracturing fluid films on the proppant particles,
and an optional liquid carrier fluid for, inter alia, reducing the
viscosity of the liquid hardening agent component. It is within the
ability of one skilled in the art, with the benefit of this
disclosure, to determine whether and how much liquid carrier fluid
is needed to achieve a viscosity suitable to the subterranean
conditions.
[0022] 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-epichlorohydrin resin, polyepoxide
resin, novolak resin, polyester resin, phenol-aldehyde resin,
urea-aldehyde resin, furan resin, urethane resin, glycidyl ethers,
and mixtures thereof. Of these, bisphenol A-epichlorohydrin resin
is preferred. The resin used is included in the liquid hardenable
resin component in an amount sufficient to consolidate the coated
particulates. In some embodiments of the present invention, the
resin used is included in the liquid hardenable resin component in
the range of from about 70% to about 100% by weight of the liquid
hardenable resin component.
[0023] Any solvent that is compatible with the hardenable resin and
achieves the desired viscosity effect is suitable for use in the
present invention. Preferred solvents are those having high flash
points (most preferably about 125.degree. F.) due to in part to
safety concerns. As described above, use of a solvent in the
hardenable resin composition is optional but may be desirable to
reduce the viscosity of the hardenable resin component for a
variety of reasons including 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 whether and how
much solvent is needed to achieve a suitable viscosity. Solvents
suitable for use in the present invention include, but are not
limited to, 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, and fatty acid methyl esters.
[0024] Examples of the hardening agents that can be used in the
liquid hardening agent component of the two-component epoxy based
resin of the present invention include, but are not limited to,
amines, aromatic amines, polyamines, aliphatic amines,
cyclo-aliphatic amines, amides, polyamides, 2-ethyl-4-methyl
imidazole, and 1,1,3-trichlorotrifluoroaceto- ne. Selection of a
preferred hardening agent depends, in part, on the temperature of
the formation in which the hardening agent will be used. By way of
example and not of limitation, in subterranean formations having a
temperature from about 60.degree. F. to about 250.degree. F.,
amines and cyclo-aliphatic amines such as piperidine,
triethylamine, N,N-dimethylaminopyridine, benzyldimethylamine,
tris(dimethylaminomethyl) phenol, and
2-(N.sub.2N-dimethylaminomethyl)phenol are preferred with
N,N-dimethylaminopyridine most preferred. In subterranean
formations having higher temperatures, 4,4'-diaminodiphenyl sulfone
may be a suitable hardening agent. The hardening agent used is
included in the liquid hardening agent component in an amount
sufficient to consolidate the coated particulates. In some
embodiments of the present invention, the hardening agent used is
included in the liquid hardenable resin component in the range of
from about 40% to about 60% by weight of the liquid hardening agent
component.
[0025] The silane coupling agent may be used, inter alia, to act as
a mediator to help bond the resin to the sand surface. Examples of
silane coupling agents that can be used in the liquid hardening
agent component of the two-component consolidation fluids of the
present invention include, but are not limited to,
n-2-(aminoethyl)-3-aminopropyltrimethoxy- silane,
3-glycidoxypropyltrimethoxysilane, and n-beta-(aminoethyl)-gamma-a-
minopropyl trimethoxysilane. The silane coupling agent used is
included in the liquid hardening agent component in an amount
capable of sufficiently bonding the resin to the particulate. In
some embodiments of the present invention, the silane coupling
agent used is included in the liquid hardenable resin component in
the range of from about 0.1% to about 3% by weight of the liquid
hardening agent component.
[0026] Any surfactant compatible with the liquid hardening agent
may be used in the present invention. Such surfactants include, but
are not limited to, an ethoxylated nonyl phenol phosphate ester,
mixtures of one or more cationic surfactants and one or more
non-ionic surfactants, and an alkyl phosphonate surfactant. The
mixtures of one or more cationic and nonionic surfactants are
described in U.S. Pat. No. 6,311,773, the relevant disclosure of
which is incorporated herein by reference. A C.sub.12-C.sub.22
alkyl phosphonate surfactant is preferred. The surfactant or
surfactants used are included in the liquid hardening agent
component in an amount in the range of from about 2% to about 15%
by weight of the liquid hardening agent component.
[0027] Use of a diluent or liquid carrier fluid in the hardenable
resin composition is optional and may be used to reduce the
viscosity of the hardenable resin component 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 whether
and how much liquid carrier fluid is needed to achieve a viscosity
suitable to the subterranean conditions. Any suitable carrier fluid
that is compatible with the hardenable resin and achieves the
desired viscosity effects is suitable for use in the present
invention. The liquid carrier fluids that can be used in the liquid
hardening agent component of the two-component epoxy based coating
material of the present invention preferably include those having
high flash points (most preferably above about 125.degree. F.).
Examples of liquid carrier fluids suitable for use in the present
invention include, but are not limited to, dipropylene glycol
methyl ether, dipropylene glycol dimethyl ether, dimethyl
formamide, diethyleneglycol methyl ether, ethyleneglycol butyl
ether, diethyleneglycol butyl ether, propylene carbonate,
d'limonene, and fatty acid methyl esters.
[0028] Another resin suitable for use in the methods of the present
invention is a furan-based resin. Suitable furan-based resins
include, but are not limited to, furfuryl alcohol, a mixture
furfuryl alcohol with an aldehyde, and a mixture of furan resin and
phenolic resin. The 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 acetate,
and furfuryl acetate.
[0029] Still another resin suitable for use in the methods of the
present invention is a phenolic-based resin. Suitable
phenolic-based resins include, but are not limited to, terpolymers
of phenol, phenolic formaldehyde resins, and a mixture of phenolic
and furan resins. The phenolic-based resin may be combined with a
solvent to control viscosity if desired. Suitable solvents for use
in the phenolic-based consolidation fluids of the present invention
include, but are not limited to butyl acetate, butyl lactate,
furfuryl acetate, and 2-butoxy ethanol.
[0030] Another resin suitable for use in the methods of the present
invention is a HT epoxy-based resin. Suitable HT epoxy-based
components included, but are not limited to, bisphenol
A-epichlorohydrin resin, polyepoxide resin, novolac resin,
polyester resin, glycidyl ethers, and mixtures thereof. The HT
epoxy-based resin may be combined with a solvent to control
viscosity if desired. Suitable solvents for use with the HT
epoxy-based resins of the present invention are those solvents
capable of substantially dissolving the HT epoxy-resin chosen for
use in the consolidation fluid. Such solvents include, but are not
limited to, dimethyl sulfoxide and dimethyl formamide. A co-solvent
such as dipropylene glycol methyl ether, dipropylene glycol
dimethyl ether, dimethyl formamide, diethylene glycol methyl ether,
ethylene glycol butyl ether, diethylene glycol butyl ether,
propylene carbonate, d'limonene, and fatty acid methyl esters, also
may be used in combination with the solvent.
[0031] Yet another resin suitable for use in the methods of the
present invention is a phenol/phenol formaldehyde/furfuryl alcohol
resin comprising from about 5% to about 30% phenol, from about 40%
to about 70% phenol formaldehyde, from about 10 to about 40%
furfuryl alcohol, from about 0.1% to about 3% of a silane coupling
agent, and from 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,
3-glycidoxypropyltrimetho- xysilane, and
n-beta-(aminoethyl)-gamma-aminopropyl trimethoxysilane. Suitable
surfactants include, but are not limited to, an ethoxylated nonyl
phenol phosphate ester, mixtures of one or more cationic
surfactants and one or more non-ionic surfactants, and an alkyl
phosphonate surfactant.
[0032] Some embodiments of the methods of the present invention
further comprise the step of puncturing the subterranean formation
surrounding a horizontal well bore located in a substantially
consolidated subterranean formation before the step of
hydraulically fracturing the formation. The stimulation and
completion methods of the present invention comprising the step of
puncturing the formation are particularly well suited for use in
highly deviated and horizontal well bores that penetrate
substantially consolidated formations. Substantially consolidated
formations help in maintaining the integrity of the well bore, and
thus helping to prevent well bore collapse and excessive formation
sand migration into the well bore. In puncturing the formation,
unconsolidated or weakly consolidated regions located above or
below the substantially consolidated well bore region may be put
into fluid communication with the well bore, thus enhancing
production without destabilizing the well bore. The methods of the
present invention are useful in open hole well bores, well bores
having a non-cemented liner, and cased and cemented well bores.
[0033] In most subterranean formation structures, consolidated and
unconsolidated strata form on top of one another. Thus, the
punctures are preferably performed at either the top side of the
horizontal well bore (i.e. 12-o'clock or 0.degree.), the bottom
side of the horizontal well bore (i.e. 6-o'clock or 180.degree.),
or both (substantially 180.degree. phasing). FIG. 3 illustrates
these three orientations of punctures in a horizontal well bore. By
way of example, where the substantially consolidated portion of the
formation containing the well bore is bordered on the top by an
unconsolidated region, at least the top of the horizontal well bore
is preferably punctured.
[0034] Any known puncturing technique may be used in the methods of
the present invention, including but not limited to, perforating
and hydrajetting. Hydrajetting generally involves the use of a
hydrajetting tool such as those described in U.S. Pat. Nos.
5,765,642, 5,494,103, and 5,361,856, the relevant portions of which
are herein incorporated by reference. In a common hydrajetting
operation, a hydrajetting tool having at least one fluid jet
forming nozzle is positioned adjacent to a formation to be
fractured, and fluid is then jetted through the nozzle against the
formation at a pressure sufficient to form a cavity, or slot
therein to fracture the formation by stagnation pressure in the
cavity. Because the jetted fluids would have to flow out of the
slot in a direction generally opposite to the direction of the
incoming jetted fluid, they are trapped in the slot and create a
relatively high stagnation pressure at the tip of a cavity. This
high stagnation pressure may cause a micro-fracture to be formed
that extends a short distance into the formation. That
micro-fracture may be further extended by pumping a fluid into the
well bore to raise the ambient fluid pressure exerted on the
formation while the formation is being hydrajetted. Such a fluid in
the well bore will flow into the slot and fracture produced by the
fluid jet and, if introduced into the well bore at a sufficient
rate and pressure, may be used to extend the fracture an additional
distance from the well bore into the formation.
[0035] Therefore, the present invention is well adapted to carry
out the objects and attain the ends and advantages mentioned as
well as those that are inherent therein. While numerous changes may
be made by those skilled in the art, such changes are encompassed
within the spirit and scope of this invention as defined by the
appended claims.
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