U.S. patent application number 11/271377 was filed with the patent office on 2007-05-10 for methods for treating a subterranean formation with a curable composition using a jetting tool.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Philip D. Nguyen, Jim B. Surjaatmadja.
Application Number | 20070102156 11/271377 |
Document ID | / |
Family ID | 37616955 |
Filed Date | 2007-05-10 |
United States Patent
Application |
20070102156 |
Kind Code |
A1 |
Nguyen; Philip D. ; et
al. |
May 10, 2007 |
Methods for treating a subterranean formation with a curable
composition using a jetting tool
Abstract
A method of treating a subterranean formation is provided, the
method comprising the steps of: positioning a jetting tool in a
wellbore penetrating the subterranean formation, wherein the
jetting tool comprises at least one fluid jet forming nozzle; and
delivering a curable composition through the jetting tool and to
the formation, wherein the curable composition: cures to form a
solid substance or a semi-solid, gel-like substance, and is a fluid
having a sufficiently low viscosity to penetrate into the
formation. The methods according to the invention are particularly
suited for treating weakly consolidated or unconsolidated
formations with a hardenable resin composition to help consolidate
the formation.
Inventors: |
Nguyen; Philip D.; (Duncan,
OK) ; Surjaatmadja; Jim B.; (Duncan, OK) |
Correspondence
Address: |
Halliburton Energy Services, Inc.;Robert A. Kent
2600 S. 2nd Street
Duncan
OK
73536-0440
US
|
Assignee: |
Halliburton Energy Services,
Inc.
|
Family ID: |
37616955 |
Appl. No.: |
11/271377 |
Filed: |
November 10, 2005 |
Current U.S.
Class: |
166/280.2 ;
166/281; 166/298 |
Current CPC
Class: |
E21B 43/025 20130101;
E21B 43/261 20130101; E21B 43/267 20130101; E21B 43/114
20130101 |
Class at
Publication: |
166/280.2 ;
166/281; 166/298 |
International
Class: |
E21B 43/267 20060101
E21B043/267 |
Claims
1. A method of treating a subterranean formation, the method
comprising the steps of: a. positioning a jetting tool in a
wellbore penetrating the subterranean formation, wherein the
jetting tool comprises at least one fluid jet forming nozzle; and
b. delivering a curable composition through the jetting tool and to
the formation, wherein i. at least a component of the curable
composition is capable of curing to form a solid substance or a
semi-solid, gel-like substance, and ii. the curable composition is
a fluid having a sufficiently low viscosity to penetrate into the
formation.
2. The method according to claim 1, wherein the viscosity is
sufficiently low that no substantial amount of residue remains
behind filling the pore spaces of the formation as the curable
composition penetrates into the formation.
3. The method according to claim 1, wherein the apparent viscosity
of the curable composition is preferably below about 100 cP.
4. The method according to claim 3, wherein the apparent viscosity
of the curable composition is measured within the range of the
bottom hole static temperature of the subterranean formation.
5. The method according to claim 4, wherein the apparent viscosity
of the curable composition is measured at the lower limit of the
bottom hole static temperature of the subterranean formation.
6. The method according to claim 1, wherein the curable composition
is a hardenable resin composition.
7. The method according to claim 1, further comprising the step of:
isolating an interval of the wellbore in the subterranean
formation, wherein the step of positioning a jetting tool further
comprises positioning the jetting tool in the isolated
interval.
8. The method according to claim 1, wherein the step of delivering
a curable composition through the jetting tool and to the formation
further comprises: filling the wellbore interval under sufficient
pressure to force the curable composition into the formation.
9. The method according to claim 1, wherein the step of delivering
a curable composition through the jetting tool and to the formation
further comprises: delivering the curable composition through the
jetting tool under conditions sufficient to direct and pressure the
curable composition into the formation.
10. The method according to claim 8, wherein the step of delivering
a curable composition through the jetting tool and to the formation
further comprises: delivering the curable composition into the
formation under conditions that are not sufficient to initiate a
fracture in the formation.
11. The method according to claim 1, further comprising the step
of: injecting a fracturing fluid through the jetting tool under
conditions sufficient to erode a portion of the wall of the well
bore and to initiate at least one fracture extending into the
formation.
12. The method according to claim 11, wherein the step of injecting
a fracturing fluid through the jetting tool to initiate at least
one fracture is separate from the step of delivering a curable
composition through the jetting tool and to the formation, and
wherein the fracturing fluid is different than the curable
composition.
13. The method according to claim 12, comprising performing the
step of injecting a fracturing fluid through the jetting tool to
initiate at least one fracture before performing the step of
delivering a curable composition through the jetting tool and to
the formation.
14. The method according to claim 11, wherein during at least part
of the step of injecting a fracturing fluid through the jetting
tool, the fracturing fluid comprises a base fluid and a particulate
material.
15. The method according to claim 14, wherein the viscosity of the
curable composition is less than the viscosity of the base
fluid.
16. The method according to claim 14, wherein the particulate
material is coated with a curable composition.
17. The method according to claim 16, wherein the curable
composition that is used for the step of depositing a proppant
coated with a curable composition into the fracture in the
formation has a sufficiently high viscosity to form a coating on
the proppant.
18. The method according to claim 1, further comprising the step
of: flowing back or producing fluid from the formation.
19. A method of treating a subterranean formation, the method
comprising the steps of: a. isolating an interval of the wellbore
penetrating the subterranean formation; b. positioning a jetting
tool in the isolated interval of the subterranean formation,
wherein the jetting tool comprises at least one fluid jet forming
nozzle; c. injecting a fracturing fluid through the jetting tool
under conditions sufficient to erode a portion of the wall of the
well bore and to initiate at least one fracture extending into the
formation; and d. delivering a curable composition through the
jetting tool and to the formation, wherein i. at least a component
of the curable composition is capable of curing to form a solid
substance or a semi-solid, gel-like substance, and ii. the curable
composition is a fluid having a sufficiently low viscosity to
penetrate into the formation.
20. A method of treating a subterranean formation, wherein the
formation is weakly consolidated or unconsolidated, the method
comprising the steps of: a. positioning a jetting tool a wellbore
penetrating the subterranean formation, wherein the jetting tool
comprises at least one fluid jet forming nozzle; b. injecting a
fracturing fluid through the jetting tool under conditions
sufficient to erode a portion of the wall of the well bore and to
initiate at least one fracture extending into the formation; and c.
delivering a curable composition through the jetting tool and to
the formation, wherein i. at least a component of the curable
composition is capable of curing to form a solid substance or a
semi-solid, gel-like substance, and ii. the curable composition is
a fluid having a sufficiently low viscosity to penetrate into the
formation.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not Applicable.
REFERENCE TO A MICROFICHE APPENDIX
[0003] Not applicable.
TECHNICAL FIELD
[0004] This invention relates generally to improvements in methods
that are used to stimulate hydrocarbon (e.g., oil & gas)
production from a subterranean formation penetrated by a wellbore.
More particularly, this invention relates to methods of treating a
subterranean formation using a jetting tool.
BACKGROUND
[0005] U.S. Pat. No. 5,249,628 issued Oct. 5, 1993, having for
named inventor Jim B. Surjaatmadja, and filed on Sep. 29, 1992
discloses casing slip joints provided on opposite sides of a
fracture initiation location to accommodate casing and formation
movement during fracturing of a well. In another aspect of the
invention, the fracture initiation location is provided by forming
openings through the well casing and then forming fan-shaped slots
in the formation surrounding the casing. Those slots are formed by
a hydraulic jet which is directed through the opening and then
pivoted generally about the point of the opening. These fan-shaped
slots circumscribe an angle about the axis of the casing
substantially greater than the angle circumscribed by the opening
itself through which the slot was formed. These techniques are
particularly applicable to fracturing of horizontal wells. See U.S.
Pat. No. 5,249,628, Abstract. The entirety of U.S. Pat. No.
5,249,628 is incorporated herein by reference.
[0006] U.S. Pat. No. 5,361,856 issued Nov. 8, 1994, having for
named inventors Jim B. Surjaatmadja, Steven L. Holden, and David D.
Szarka, and filed on Sep. 9, 1993, discloses a well jetting
apparatus for use in fracturing of a well. Fracture initiation is
provided by forming openings through the well casing and then
forming fan-shaped slots in the formation surrounding the casing.
Those slots are formed by the jetting apparatus which has at least
one hydraulic jet directed through the opening. The apparatus may
be pivoted generally about the point of the opening to form the
slots, but preferably a plurality of slots are formed substantially
simultaneously. These fan-shaped slots circumscribe an angle about
the axis of the casing substantially greater than the angle
circumscribed by the opening itself through which the slot was
formed. These techniques are particularly applicable to fracturing
of horizontal wells, but the apparatus may be used in any well
configuration. See U.S. Pat. No. 5,361,856, Abstract. The entirety
of U.S. Pat. No. 5,361,856 is incorporated herein by reference.
[0007] U.S. Pat. No. 5,765,642 issued Jun. 16, 1998, having for
named inventor Jim B. Surjaatmadja, and filed on Dec. 23, 1996
discloses methods of fracturing a subterranean formation, which
basically comprise positioning a hydrajetting tool having at least
one fluid jet forming nozzle in the well bore adjacent the
formation to be fractured and jetting fluid through the nozzle
against the formation at a pressure sufficient to form a fracture
in the formation. See U.S. Pat. No. 5,765,642, Abstract. The
entirety of U.S. Pat. No. 5,765,642 is incorporated herein by
reference.
[0008] U.S. Pat. No. 6,776,236 issued Aug. 17, 2004, having for
named inventor Phillip D. Nguyen, and filed on Oct. 16, 2002,
discloses methods of completing unconsolidated hydrocarbon
producing zones penetrated by cased and cemented well bores. The
methods include the steps of forming spaced openings through the
casing and cement and injecting a first hardenable resin
composition through the openings into the unconsolidated producing
zone adjacent to the well bore. Without waiting for the first
hardenable resin composition to harden, a fracturing fluid
containing proppant particles coated with a second hardenable resin
composition is injected through the openings into the
unconsolidated producing zone at a rate and pressure sufficient to
fracture the producing zone. The proppant particles coated with the
second hardenable resin composition are deposited in the fractures
and the first and second hardenable resin compositions are allowed
to harden by heat. See U.S. Pat. No. 6,776,236, Abstract. The
entirety of U.S. Pat. No. 6,776,236 is incorporated herein by
reference.
SUMMARY OF THE INVENTION
[0009] According to the invention, a method of treating a
subterranean formation, is provided, the method comprising the
steps of: positioning a jetting tool in a wellbore penetrating the
subterranean formation, wherein the jetting tool comprises at least
one fluid jet forming nozzle; and delivering a curable composition
through the jetting tool and to the formation, wherein at least a
component of the curable composition is capable of curing to form a
solid substance or a semi-solid, gel-like substance, and the
curable composition is a fluid having a sufficiently low viscosity
to penetrate into the formation.
[0010] According to another aspect of the invention, a method of
treating a subterranean formation is provided, the method
comprising the steps of: isolating an interval of the wellbore
penetrating the subterranean formation; positioning a jetting tool
in the isolated interval of the subterranean formation, wherein the
jetting tool comprises at least one fluid jet forming nozzle;
injecting a fracturing fluid through the jetting tool under
conditions sufficient to erode a portion of the wall of the well
bore and to initiate at least one fracture extending into the
formation; and delivering a curable composition through the jetting
tool and to the formation, wherein at least a component of the
curable composition is capable of curing to form a solid substance
or a semi-solid, gel-like substance, and the curable composition is
a fluid having a sufficiently low viscosity to penetrate into the
formation.
[0011] According to yet another aspect of the invention, a method
of treating a subterranean formation is provided, wherein the
formation is weakly consolidated or unconsolidated, the method
comprising the steps of: positioning a jetting tool a wellbore
penetrating the subterranean formation, wherein the jetting tool
comprises at least one fluid jet forming nozzle; injecting a
fracturing fluid through the jetting tool under conditions
sufficient to erode a portion of the wall of the well bore and to
initiate at least one fracture extending into the formation; and
delivering a curable composition through the jetting tool and to
the formation, wherein at least a component of the curable
composition is capable of curing to form a solid substance or a
semi-solid, gel-like substance, and the curable composition is a
fluid having a sufficiently low viscosity to penetrate into the
formation.
[0012] Therefore, from the foregoing, it is a general object of the
present invention to provide improved methods for treating a
formation including the use of a jetting tool and for delivering a
curable composition through the jetting tool. Other and further
objects, features and advantages of the present invention will be
readily apparent to those skilled in the art when the following
description of the preferred embodiments is read in conjunction
with the accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] FIG. 1A is a schematic diagram illustrating a jetting tool
creating perforation tunnels through an uncased horizontal wellbore
in a first zone of a subterranean formation.
[0014] FIG. 1B is a schematic diagram illustrating a jetting tool
creating perforation tunnels through a cased horizontal wellbore in
a first zone of a subterranean formation.
[0015] FIG. 2 is a schematic diagram illustrating a cross-sectional
view of the jetting tool shown in FIG. 1 forming four equally
spaced perforation tunnels in the first zone of the subterranean
formation.
[0016] FIG. 3 is a schematic diagram illustrating the creation of
fractures in the first zone by the jetting tool wherein the plane
of the fracture(s) is perpendicular to the wellbore axis.
[0017] FIGS. 4A and 4B illustrate operation of a jetting tool for
use in carrying out the methods according to the present
invention.
DETAILED DESCRIPTION
[0018] As used herein and in the appended claims, the words
"comprise," "has," and "include" and all grammatical variations
thereof are each intended to have an open, non-limiting meaning
that does not exclude additional elements or parts of an assembly,
subassembly, or structural element.
[0019] 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.
[0020] In general, the invention according to the present invention
provides a method of treating a subterranean formation, the method
comprising the steps of: positioning a jetting tool in a wellbore
penetrating the subterranean formation, wherein the jetting tool
comprises at least one fluid jet forming nozzle; and delivering a
curable composition through the jetting tool and to the formation,
wherein at least a component of the curable composition is capable
of curing to form a solid substance or a semi-solid, gel-like
substance, and the curable composition is a fluid having a
sufficiently low viscosity to penetrate into the formation. The low
viscosity fluid can be obtained by thinning down higher viscosity
fluids using solvents.
[0021] Preferably, the viscosity is sufficiently low that no
substantial amount of residue remains behind filling the pore
spaces of the formation as the curable composition penetrates into
the formation. This allows the placement of the curable composition
to be better controlled and without undesired effects on the
permeability of the formation.
[0022] The low-viscosity curable composition is capable of
penetrating the subterranean formation at relatively low flow rate
and pressure differential. For example, the delivery rate through
the jetting tool and to the formation would typically be less than
about 2 barrels per minute.
[0023] Even when the method is used to treat a proppant pack in a
fracture in a subterranean formation or a gravel pack adjacent the
formation, the curable composition should have a sufficiently low
viscosity to penetrate into the formation. This avoids risking any
substantial plugging of the permeability of the surrounding
formation.
[0024] Regardless of the type of curable composition chosen for use
in treating a subterranean formation, the viscosity of the curable
composition should be sufficiently low to be able to penetrate into
the subterranean formation. For example, for a weakly consolidated
or unconsolidated formation, the viscosity should be sufficient low
to penetrate into the rock of the formation.
[0025] To achieve the desired penetration, the apparent viscosity
of the curable composition is preferably below about 100 centipoise
("cP"), more preferably below about 50 cP, and most preferably
below about 10 cP. The apparent viscosity is preferably measured
within the range of the bottom hole static temperature ("BHST") of
the subterranean formation. More preferably, the apparent viscosity
of the curable composition is measured at the lower limit of the
bottom hole static temperature of the subterranean formation.
Achieving the desired viscosity will generally involve either the
use of a solvent, although the use of heat can be used to reduce
the viscosity of the chosen curable composition.
[0026] Factors that may influence the amount of solvent needed
include the geographic location of the well and the surrounding
environmental conditions. In some embodiments, suitable
consolidating fluid-to-solvent ratios range from about 1:0.2 to
about 1:20. It is within the ability of one skilled in the art,
with the benefit of this disclosure, to determine a sufficient
amount of a suitable solvent to achieve the desired viscosity and,
thus, to achieve the preferred penetration into the subterranean
formation. Placement or mixing of the solvents can be done uphole
(on surface) or can be performed in situ (downhole). This can be
achieved by taking advantage of the annular passages, or a second
tubular system downhole.
[0027] The method is particularly useful where the formation is a
weakly consolidated or unconsolidated formation. In such a
situation, the curable composition is preferably a hardenable resin
composition.
[0028] For consolidation applications, in which case the curable
compositions are sometimes referred to as consolidation fluids,
suitable resins include all resins know in the art that are capable
of forming a hardened, consolidated mass. 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. Again, this does
not preclude the ability of mixing the catalysts downhole when so
desired.
[0029] 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.
[0030] Any solvent that is compatible with the chosen resin and
achieves the desired viscosity effect is suitable for use in the
present invention. Some preferred solvents are those having high
flash points (e.g., about 125.degree. F.) because of, among other
things, environmental and safety concerns; such solvents include
butyl lactate, butylglycidyl ether, dipropylene glycol methyl
ether, dipropylene glycol dimethyl ether, dimethyl formanide,
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.
[0031] One resin-type coating material suitable for use in the
methods 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 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 and the surrounding weather
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 certain
circumstances. The second component is the liquid hardening agent
component, which is comprised of a hardening agent, a silane
coupling agent, a surfactant, an optional hydrolyzable ester for,
among other things, breaking gelled fracturing fluid films on the
proppant particles, and an optional liquid carrier fluid for, among
other things, 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 if and how much liquid
carrier fluid is needed to achieve a viscosity suitable to the
subterranean conditions.
[0032] Examples of hardenable resins that can be used in the
hardenable resin component include, but are not limited to, organic
resins such as bisphenol A diglycidyl ether resin, butoxymethyl
butyl glycidyl ether resin, bisphenol A-epichlorohydrin resin,
polyepoxide resin, novolak resin, polyester resin, phenol-aldehyde
resin, urea-aldehyde resin, furan resin, urethane resin, a glycidyl
ether resin, and combinations thereof. The hardenable resin used is
included in the hardenable resin component in an amount in the
range of from about 60% to about 100% by weight of the hardenable
resin component. In some embodiments the hardenable resin used is
included in the hardenable resin component in an amount of about
70% to about 90% by weight of the hardenable resin component.
[0033] Any solvent that is compatible with the hardenable resin and
achieves the desired viscosity effect is suitable for use in the
hardenable resin component of the integrated consolidation fluids
of the present invention. Some preferred solvents are those having
high flash points (e.g., about 125.degree. F.) because of, among
other things, environmental and safety concerns; 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 C2 to C6 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
composition chosen and is within the ability of one skilled in the
art with the benefit of this disclosure.
[0034] As described above, use of a solvent in the 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. 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 hardenable resin
component is in the range of from about 0.1% to about 30% by weight
of the hardenable resin component. Optionally, the hardenable resin
component may be heated to reduce its viscosity, in place of, or in
addition to, using a solvent.
[0035] Examples of the hardening 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,
piperazine, derivatives of piperazine (e.g., aminoethylpiperazine),
2H-pyrrole, pyrrole, imidazole, pyrazole, pyridine, pyrazine,
pyrimidine, pyridazine, indolizine, isoindole, 3H-indole, indole,
1H-indazole, purine, 4H-quinolizine, quinoline, isoquinoline,
phthalazine, naphthyridine, quinoxaline, quinazoline, 4H-carbazole,
carbazole, .beta.-carboline, phenanthridine, acridine,
phenathroline, phenazine, imidazolidine, phenoxazine, cinnoline,
pyrrolidine, pyrroline, imidazoline, piperidine, indoline,
isoindoline, quinuclindine, morpholine, azocine, azepine,
2H-azepine, 1,3,5-triazine, thiazole, pteridine, dihydroquinoline,
hexa methylene imine, indazole, amines, aromatic amines,
polyamines, aliphatic amines, cyclo-aliphatic amines, amides,
polyamides, 2-ethyl-4-methyl imidazole,
1,1,3-trichlorotrifluoroacetone, 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 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-(N2N-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. 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
70.degree. F. to as high as about 350.degree. F. 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. In some embodiments the hardenable resin used is
included in the hardenable resin component in an amount of about
45% to about 55% by weight of the liquid hardening agent
component.
[0036] The silane coupling agent may be used, among other things,
to act as a mediator to help bond the resin to formation
particulates and-or proppant. Examples of suitable silane coupling
agents include, but are not limited to,
N-.beta.-(aminoethyl)-.gamma.-aminopropyl trimethoxysilane,
N-2-(aminoethyl)-3-aminopropyltrimethoxysilane,
3-glycidoxypropyltrimethoxysilane, and combinations thereof. 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.
[0037] Any surfactant compatible with the hardening agent and
capable of facilitating the coating of the resin onto particles in
the subterranean formation may be used in the hardening agent
component of the integrated consolidation fluids of the present
invention. Such surfactants include, but are not limited to, an
alkyl phosphonate surfactant (e.g., a Cl.sub.2-C.sub.22 alkyl
phosphonate surfactant), an ethoxylated nonyl phenol phosphate
ester, one or more cationic surfactants, and one or more nonionic
surfactants. Mixtures of one or more cationic and nonionic
surfactants also may be suitable. Examples of such surfactant
mixtures are described in U.S. Pat. No. 6,311,773 issued to Todd et
al. on Nov. 6, 2001, the relevant disclosure of which is
incorporated herein by reference. The surfactant or surfactants
used are included in the liquid hardening agent component in an
amount in the range of from about 1% to about 10% by weight of the
liquid hardening agent component.
[0038] While not required, examples of hydrolysable esters that can
be used in the hardening agent component of the integrated
consolidation fluids of the present invention include, but are not
limited to, a mixture of dimethylglutarate, dimethyladipate, and
dimethylsuccinate; sorbitol; catechol; dimethylthiolate; methyl
salicylate; dimethyl salicylate; dimethylsuccinate;
ter-butylhydroperoxide; and combinations thereof. When used, a
hydrolyzable ester is included in the hardening agent component in
an amount in the range of from about 0.1% to about 3% by weight of
the hardening agent component. In some embodiments a hydrolysable
ester is included in the hardening agent component in an amount in
the range of from about 1% to about 2.5% by weight of the hardening
agent component.
[0039] 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 if 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. Some preferred 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 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 liquid carrier fluids include
aqueous dissolvable solvents such as, 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 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
liquid carrier fluid is dependent on the resin composition chosen
and is within the ability of one skilled in the art with the
benefit of this disclosure.
[0040] Another type of 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 resins,
mixtures furfuryl alcohol resins and aldehydes, and a mixture of
furan resins and phenolic resins. Of these, furfuryl alcohol resins
are 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.
[0041] Still another type of 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. Of these, a mixture of phenolic and furan resins
is preferred. A 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. Of these, 2-butoxy ethanol
is preferred.
[0042] Another type of resin suitable for use in the methods of the
present invention is a HT epoxy-based resin. Suitable HT
epoxy-based components include, but are not limited to, bisphenol
A-epichlorohydrin resins, polyepoxide resins, novolac resins,
polyester resins, glycidyl ethers and mixtures thereof. Of these,
bisphenol A-epichlorohydrin resins are preferred. An 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 a
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, may also be used in
combination with the solvent.
[0043] Yet another resin-type coating material 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-glycidoxypropyltrimethoxysilane, 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.
[0044] Gelable compositions suitable for use in the present
invention include those compositions that cure to form a
semi-solid, gel-like substance. The gelable composition may be any
gelable liquid composition capable of converting into a gelled
substance capable of substantially consolidating the formation
while allowing the formation to remain flexible. As referred to
herein, the term "flexible" refers to a state wherein the treated
portion of the formation is relatively malleable and elastic and
able to withstand substantial pressure cycling without substantial
breakdown of the formation. Thus, the resultant gelled substance
stabilizes the treated portion of the formation while allowing the
formation to absorb the stresses created during pressure cycling.
As a result, the gelled substance may aid in preventing breakdown
of the formation both by stabilizing and by adding flexibility to
the treated portion. Examples of suitable gelable liquid
compositions include, but are not limited to, (1) gelable resin
compositions, (2) gelable aqueous silicate compositions, (3)
crosslinkable aqueous polymer compositions, and (4) polymerizable
organic monomer compositions.
[0045] Certain embodiments of the gelable liquid compositions of
the present invention comprise gelable resin compositions that cure
to form flexible gels. Unlike the hardenable resin compositions
described above, which cure into hardened masses, the gelable resin
compositions cure into flexible, gelled substances that form
resilient gelled substances between the particulates of the treated
zone of the unconsolidated formation. Gelable resin compositions
allow the treated portion of the formation to remain flexible and
resist breakdown.
[0046] Generally, the gelable resin compositions useful in
accordance with this invention comprise a curable resin, a diluent,
and a resin curing agent. When certain resin curing agents, such as
polyamides, are used in the curable resin compositions, the
compositions form the semi-solid, gelled substances described
above. Where the resin curing agent used may cause the organic
resin compositions to form hard, brittle material rather than a
desired gelled substance, the curable resin compositions may
further comprise one or more "flexibilizer additives" (described in
more detail below) to provide flexibility to the cured
compositions.
[0047] Examples of gelable resins that can be used in the present
invention include, but are not limited to, organic resins such as
polyepoxide resins (e.g., Bisphenol a-epichlorihydrin resins),
polyester resins, urea-aldehyde resins, furan resins, urethane
resins, and mixtures thereof. Of these, polyepoxide resins are
preferred.
[0048] Any diluent that is compatible with the gelable resin and
achieves the desired viscosity effect is suitable for use in the
present invention. Examples of diluents that may be used in the
gelable resin compositions of the present invention include, but
are not limited to, phenols; formaldehydes; furfuryl alcohols;
furfurals; alcohols; ethers such as butyl glycidyl ether and cresyl
glycidyl etherphenyl glycidyl ether; and mixtures thereof. In some
embodiments of the present invention, the diluent comprises butyl
lactate. The diluent may be used to reduce the viscosity of the
gelable resin composition. Among other things, the diluent acts to
provide flexibility to the cured composition. The diluent may be
included in the gelable resin composition in an amount sufficient
to provide the desired viscosity effect. Subject to providing the
desired viscosity effect, generally, the diluent used is included
in the gelable resin composition in amount in the range of from
about 5% to about 75% by weight of the curable resin.
[0049] Generally, any resin curing agent that may be used to cure
an organic resin is suitable for use in the present invention. When
the resin curing agent chosen is an amide or a polyamide, generally
no flexibilizer additive will be required because, among other
things, such curing agents cause the gelable resin composition to
convert into a semi-solid, gelled substance. Other suitable resin
curing agents (such as an amine, a polyamine, methylene dianiline,
and other curing agents known in the art) will tend to cure into a
hard, brittle material and will thus benefit from the addition of a
flexibilizer additive. Generally, the resin curing agent used is
included in the gelable resin composition, whether a flexibilizer
additive is included or not, in an amount in the range of from
about 5% to about 75% by weight of the curable resin. In some
embodiments of the present invention, the resin curing agent used
is included in the gelable resin composition in an amount in the
range of from about 20% to about 75% by weight of the curable
resin.
[0050] As noted above, flexibilizer additives may be used, among
other things, to provide flexibility to the gelled substances
formed from the curable resin compositions. Flexibilizer additives
may be used where the resin curing agent chosen would cause the
gelable resin composition to cure into a hard and brittle
material--rather than a desired gelled substance. For example,
flexibilizer additives may be used where the resin curing agent
chosen is not an amide or polyamide. Examples of suitable
flexibilizer additives include, but are not limited to, an organic
ester, an oxygenated organic solvent, an aromatic solvent, and
combinations thereof. Of these, ethers, such as dibutyl phthalate,
are preferred. Where used, the flexibilizer additive may be
included in the gelable resin composition in an amount in the range
of from about 5% to about 80% by weight of the gelable resin. In
some embodiments of the present invention, the flexibilizer
additive may be included in the curable resin composition in an
amount in the range of from about 20% to about 45% by weight of the
curable resin.
[0051] In other embodiments, the gelable liquid compositions of the
present invention may comprise a gelable aqueous silicate
composition. Generally, the gelable aqueous silicate compositions
that are useful in accordance with the present invention generally
comprise an aqueous alkali metal silicate solution and a
temperature activated catalyst for gelling the aqueous alkali metal
silicate solution.
[0052] The aqueous alkali metal silicate solution component of the
gelable aqueous silicate compositions generally comprise an aqueous
liquid and an alkali metal silicate. The aqueous liquid component
of the aqueous alkali metal silicate solution generally may be
fresh water, salt water (e.g., water containing one or more salts
dissolved therein), brine (e.g., saturated salt water), seawater,
or any other aqueous liquid that does not adversely react with the
other components used in accordance with this invention or with the
subterranean formation. Examples of suitable alkali metal silicates
include, but are not limited to, one or more of sodium silicate,
potassium silicate, lithium silicate, rubidium silicate, or cesium
silicate. Of these, sodium silicate is preferred. While sodium
silicate exists in many forms, the sodium silicate used in the
aqueous alkali metal silicate solution preferably has a
Na.sub.2O-to-SiO.sub.2 weight ratio in the range of from about 1:2
to about 1:4. Most preferably, the sodium silicate used has a
Na.sub.2O-to-SiO.sub.2 weight ratio in the range of about 1:3.2.
Generally, the alkali metal silicate is present in the aqueous
alkali metal silicate solution component in an amount in the range
of from about 0.1% to about 10% by weight of the aqueous alkali
metal silicate solution component.
[0053] The temperature-activated catalyst component of the gelable
aqueous silicate compositions is used, among other things, to
convert the gelable aqueous silicate compositions into the desired
semi-solid, gel-like substance described above. Selection of a
temperature-activated catalyst is related, at least in part, to the
temperature of the subterranean formation to which the gelable
aqueous silicate composition will be introduced. The
temperature-activated catalysts that can be used in the gelable
aqueous silicate compositions of the present invention include, but
are not limited to, ammonium sulfate (which is most suitable in the
range of from about 60.degree. F. to about 240.degree. F.); sodium
acid pyrophosphate (which is most suitable in the range of from
about 60.degree. F. to about 240.degree. F.); citric acid (which is
most suitable in the range of from about 60.degree. F. to about
120.degree. F.); and ethyl acetate (which is most suitable in the
range of from about 60.degree. F. to about 120.degree. F.).
Generally, the temperature-activated catalyst is present in the
gelable aqueous silicate composition in the range of from about
0.1% to about 5% by weight of the gelable aqueous silicate
composition.
[0054] In other embodiments, the gelable liquid compositions of the
present invention comprise crosslinkable aqueous polymer
compositions. Generally, suitable crosslinkable aqueous polymer
compositions comprise an aqueous solvent, a crosslinkable polymer,
and a crosslinking agent. Such compositions are similar to those
used to form gelled treatment fluids, such as fracturing fluids,
but, according to the methods of the present invention, they are
not exposed to breakers or de-linkers and so they retain their
viscous nature over time.
[0055] The aqueous solvent may be any aqueous solvent in which the
crosslinkable composition and the crosslinking agent may be
dissolved, mixed, suspended, or dispersed therein to facilitate gel
formation. For example, the aqueous solvent used may be fresh
water, salt water, brine, seawater, or any other aqueous liquid
that does not adversely react with the other components used in
accordance with this invention or with the subterranean
formation.
[0056] Examples of crosslinkable polymers that can be used in the
crosslinkable aqueous polymer compositions include, but are not
limited to, carboxylate-containing polymers and
acrylamide-containing polymers. Preferred acrylamide-containing
polymers include polyacrylamide, partially hydrolyzed
polyacrylamide, copolymers of acrylamide and acrylate, and
carboxylate-containing terpolymers and tetrapolymers of acrylate.
Additional examples of suitable crosslinkable polymers include
hydratable polymers comprising polysaccharides and derivatives
thereof and that contain one or more of the monosaccharide units
galactose, mannose, glucoside, glucose, xylose, arabinose,
fructose, glucuronic acid, or pyranosyl sulfate. Suitable natural
hydratable polymers include, but are not limited to, guar gum,
locust bean gum, tara, konjak, tamarind, starch, cellulose, karaya,
xanthan, tragacanth, and carrageenan, and derivatives of all of the
above. Suitable hydratable synthetic polymers and copolymers that
may be used in the crosslinkable aqueous polymer compositions
include, but are not limited to, polyacrylates, polymethacrylates,
polyacrylamides, maleic anhydride, methylvinyl ether polymers,
polyvinyl alcohols, and polyvinylpyrrolidone. The crosslinkable
polymer used should be included in the crosslinkable aqueous
polymer composition in an amount sufficient to form the desired
gelled substance in the subterranean formation. In some embodiments
of the present invention, the crosslinkable polymer is included in
the crosslinkable aqueous polymer composition in an amount in the
range of from about 1% to about 30% by weight of the aqueous
solvent. In another embodiment of the present invention, the
crosslinkable polymer is included in the crosslinkable aqueous
polymer composition in an amount in the range of from about 1% to
about 20% by weight of the aqueous solvent.
[0057] The crosslinkable aqueous polymer compositions of the
present invention further comprise a crosslinking agent for
crosslinking the crosslinkable polymers to form the desired gelled
substance. In some embodiments, the crosslinking agent is a
molecule or complex containing a reactive transition metal cation.
A most preferred crosslinking agent comprises trivalent chromium
cations complexed or bonded to anions, atomic oxygen, or water.
Examples of suitable crosslinking agents include, but are not
limited to, compounds or complexes containing chromic acetate
and/or chromic chloride. Other suitable transition metal cations
include chromium VI within a redox system, aluminum III, iron II,
iron III, and zirconium IV.
[0058] The crosslinking agent should be present in the
crosslinkable aqueous polymer compositions of the present invention
in an amount sufficient to provide, among other things, the desired
degree of crosslinking. In some embodiments of the present
invention, the crosslinking agent is present in the crosslinkable
aqueous polymer compositions of the present invention in an amount
in the range of from about 0.01% to about 5% by weight of the
crosslinkable aqueous polymer composition. The exact type and
amount of crosslinking agent or agents used depends upon the
specific crosslinkable polymer to be crosslinked, formation
temperature conditions, and other factors known to those
individuals skilled in the art.
[0059] Optionally, the crosslinkable aqueous polymer compositions
may further comprise a crosslinking delaying agent, such as a
polysaccharide crosslinking delaying agent derived from guar, guar
derivatives, or cellulose derivatives. The crosslinking delaying
agent may be included in the crosslinkable aqueous polymer
compositions, among other things, to delay crosslinking of the
crosslinkable aqueous polymer compositions until desired. One of
ordinary skill in the art, with the benefit of this disclosure,
will know the appropriate amount of the crosslinking delaying agent
to include in the crosslinkable aqueous polymer compositions for a
desired application.
[0060] In other embodiments, the gelled liquid compositions of the
present invention comprise polymerizable organic monomer
compositions. Generally, suitable polymerizable organic monomer
compositions comprise an aqueous-base fluid, a water-soluble
polymerizable organic monomer, an oxygen scavenger, and a primary
initiator.
[0061] The aqueous-based fluid component of the polymerizable
organic monomer composition generally may be fresh water, salt
water, brine, seawater, or any other aqueous liquid that does not
adversely react with the other components used in accordance with
this invention or with the subterranean formation.
[0062] A variety of monomers are suitable for use as the
water-soluble polymerizable organic monomers in the present
invention. Examples of suitable monomers include, but are not
limited to, acrylic acid, methacrylic acid, acrylamide,
methacrylamide, 2-methacrylamido-2-methylpropane sulfonic acid,
2-dimethylacrylamide, vinyl sulfonic acid,
N,N-dimethylaminoethylmethacrylate,
2-triethylammoniumethylmethacrylate chloride,
N,N-dimethyl-aminopropylmethacryl-amide,
methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone,
vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammonium
sulfate, and mixtures thereof. Preferably, the water-soluble
polymerizable organic monomer should be self-crosslinking. Examples
of suitable monomers which are self crosslinking include, but are
not limited to, hydroxyethylacrylate, hydroxymethylacrylate,
hydroxyethylmethacrylate, N-hydroxymethylacrylaamide,
N-hydroxymethyl-methacrylamide, polyethylene glycol acrylate,
polyethylene glycol methacrylate, polypropylene gylcol acrylate,
polypropylene glycol methacrylate, and mixtures thereof. Of these,
hydroxyethylacrylate is preferred. An example of a particularly
preferable monomer is hydroxyethylcellulose-vinyl phosphoric
acid.
[0063] The water-soluble polymerizable organic monomer (or monomers
where a mixture thereof is used) should be included in the
polymerizable organic monomer composition in an amount sufficient
to form the desired gelled substance after placement of the
polymerizable organic monomer composition into the subterranean
formation. In some embodiments of the present invention, the
water-soluble polymerizable organic monomer is included in the
polymerizable organic monomer composition in an amount in the range
of from about 1% to about 30% by weight of the aqueous-base fluid.
In another embodiment of the present invention, the water-soluble
polymerizable organic monomer is included in the polymerizable
organic monomer composition in an amount in the range of from about
1% to about 20% by weight of the aqueous-base fluid.
[0064] The presence of oxygen in the polymerizable organic monomer
composition may inhibit the polymerization process of the
water-soluble polymerizable organic monomer or monomers. Therefore,
an oxygen scavenger, such as stannous chloride, may be included in
the polymerizable monomer composition. In order to improve the
solubility of stannous chloride so that it may be readily combined
with the polymerizable organic monomer composition on the fly, the
stannous chloride may be pre-dissolved in a hydrochloric acid
solution. For example, the stannous chloride may be dissolved in a
0.1% by weight aqueous hydrochloric acid solution in an amount of
about 10% by weight of the resulting solution. The resulting
stannous chloride-hydrochloric acid solution may be included in the
polymerizable organic monomer composition in an amount in the range
of from about 0.1% to about 10% by weight of the polymerizable
organic monomer composition. Generally, the stannous chloride may
be included in the polymerizable organic monomer composition of the
present invention in an amount in the range of from about 0.005% to
about 0.1% by weight of the polymerizable organic monomer
composition.
[0065] The primary initiator is used, among other things, to
initiate polymerization of the water-soluble polymerizable organic
monomer(s) used in the present invention. Any compound or compounds
that form free radicals in aqueous solution may be used as the
primary initiator. The free radicals act, among other things, to
initiate polymerization of the water-soluble polymerizable organic
monomer present in the polymerizable organic monomer composition.
Compounds suitable for use as the primary initiator include, but
are not limited to, alkali metal persulfates; peroxides;
oxidation-reduction systems employing reducing agents, such as
sulfites in combination with oxidizers; and azo polymerization
initiators. Preferred azo polymerization initiators include
2,2'-azobis(2-imidazole-2-hydroxyethyl) propane, 2,2'-azobis
(2-aminopropane), 4,4'-azobis (4-cyanovaleric acid), and
2,2'-azobis (2-methyl-N-(2-hydroxyethyl) propionamide. Generally,
the primary initiator should be present in the polymerizable
organic monomer composition in an amount sufficient to initiate
polymerization of the water-soluble polymerizable organic
monomer(s). In certain embodiments of the present invention, the
primary initiator is present in the polymerizable organic monomer
composition in an amount in the range of from about 0.1% to about
5% by weight of the water-soluble polymerizable organic monomer(s).
One skilled in the art will recognize that as the polymerization
temperature increases, the required level of activator
decreases.
[0066] Optionally, the polymerizable organic monomer compositions
further may comprise a secondary initiator. A secondary initiator
may be used, for example, where the immature aqueous gel is placed
into a subterranean formation that is relatively cool as compared
to the surface mixing, such as when placed below the mud line in
offshore operations. The secondary initiator may be any suitable
water-soluble compound or compounds that may react with the primary
initiator to provide free radicals at a lower temperature. An
example of a suitable secondary initiator is triethanolamine. In
some embodiments of the present invention, the secondary initiator
is present in the polymerizable organic monomer composition in an
amount in the range of from about 0.1% to about 5% by weight of the
water-soluble polymerizable organic monomer(s).
[0067] Also optionally, the polymerizable organic monomer
compositions of the present invention further may comprise a
crosslinking agent for crosslinking the polymerizable organic
monomer compositions in the desired gelled substance. In some
embodiments, the crosslinking agent is a molecule or complex
containing a reactive transition metal cation. A most preferred
crosslinking agent comprises trivalent chromium cations complexed
or bonded to anions, atomic oxygen, or water. Examples of suitable
crosslinking agents include, but are not limited to, compounds or
complexes containing chromic acetate and/or chromic chloride. Other
suitable transition metal cations include chromium VI within a
redox system, aluminum III, iron II, iron III, and zirconium IV.
Generally, the crosslinking agent may be present in polymerizable
organic monomer compositions in an amount in the range of from
0.01% to about 5% by weight of the polymerizable organic monomer
composition.
[0068] The method according to the invention can be advantageously
employed for an open-hole wellbore, especially but not necessarily
in the case of a weakly consolidated or unconsolidated formation.
The method according to claim 1, wherein the wellbore is a cased or
lined wellbore.
[0069] The method can include the step of drilling the wellbore to
penetrate the formation, whereby the wellbore is an open-hole
wellbore. After drilling the open-hole wellbore, the method can
further comprise the step of installing a casing or liner in the
open-hole wellbore to form a cased or lined wellbore. If a
pre-existing open-hole wellbore is not already cased or lined, the
method can include the step of installing a casing or liner in the
wellbore to form a cased or lined wellbore.
[0070] The details of the method according to the present invention
will now be described with reference to the accompanying drawings.
First, a wellbore 10 is drilled into the subterranean formation of
interest 12 using conventional (or future) drilling techniques.
Next, depending upon the nature of the formation, the wellbore 10
is either left open hole, as shown in FIG. 1A, or lined with a
casing string or slotted liner, as shown in FIG. 1B. The wellbore
10 may be left as an uncased open hole if, for example, the
subterranean formation is highly consolidated or in the case where
the well is a highly deviated or horizontal well, which are often
difficult to line with casing. In cases where the wellbore 10 is
lined with a casing string, the casing string may or may not be
cemented to the formation. The casing in FIG. 1B is shown cemented
to the subterranean formation. Furthermore, when uncemented, the
casing liner may be either a slotted or preperforated liner or a
solid liner. Those of ordinary skill in the art will appreciate the
circumstances when the wellbore 10 should or should not be cased,
whether such casing should or should not be cemented, and whether
the casing string should be slotted, preperforated or solid.
Indeed, the present invention does not lie in the performance of
the steps of drilling the wellbore 10 or whether or not to case the
wellbore, or if so, how. The method according to the invention can
also be applied to an older well bore that has zones that are in
need of stimulation.
[0071] Once the wellbore 10 is drilled, and if deemed necessary
cased, a jetting tool 14, such as that used in the SURGIFRAC
process described in U.S. Pat. No. 5,765,642, is placed into the
wellbore 10 at a location of interest, e.g., adjacent to a first
zone 16 in the subterranean formation 12. In one exemplary
embodiment, the jetting tool 14 is attached to a tubing or coiled
tubing 18, which lowers the jetting tool 14 into the wellbore 10
and supplies it with jetting fluid. Annulus 19 is formed between
the tubing 18 and the wellbore 10. The jetting tool 14 then
operates to form perforation tunnels 20 in the first zone 16, as
shown in FIG. 1. The perforation fluid being pumped through the
jetting tool 14 contains a base fluid, which is commonly water and
abrasives (commonly sand). As shown in FIG. 2, four equally spaced
jets (in this example) of fluid 22 are injected into the first zone
16 of the subterranean formation 12. As those of ordinary skill in
the art will recognize, the jetting tool 14 can have any number of
jets, configured in a variety of combinations along and around the
tool.
[0072] In the next step of the well completion method according to
the present invention, the first zone 16 is fractured. This may be
accomplished by any one of a number of ways. In one exemplary
embodiment, the jetting tool 14 injects a high pressure fracture
fluid into the perforation tunnels 20. As those of ordinary skill
in the art will appreciate, the pressure of the fracture fluid
exiting the jetting tool 14 is sufficient to fracture the formation
in the first zone 16. Using this technique, the jetted fluid forms
cracks or fractures 24 along the perforation tunnels 20, as shown
in FIG. 3. In a subsequent step, an acidizing fluid may be injected
into the formation through the jetting tool 14. The acidizing fluid
etches the formation along the cracks 24 thereby widening them.
[0073] In another exemplary embodiment, the jetted fluid carries a
proppant into the cracks or fractures 24. The injection of
additional fluid extends the fractures 24 and the proppant prevents
them from closing up at a later time. The present invention
contemplates that other fracturing methods may be employed. For
example, the perforation tunnels 20 can be fractured by pumping a
hydraulic fracture fluid into them from the surface through annulus
19. Next, either and acidizing fluid or a proppant fluid can be
injected into the perforation tunnels 20, so as to further extend
and widen them. Other fracturing techniques can be used to fracture
the first zone 16.
[0074] FIGS. 4A-B illustrate the details of an example of a jetting
tool 14 for use in carrying out the methods of the present
invention. Jetting tool 14 comprises a main body 40, which is
cylindrical in shape and formed of a ferrous metal. The main body
40 has a top end 42 and a bottom end 44. The top end 42 connects to
tubing or coiled tubing 18 for operation within the wellbore 10.
The main body 40 has a plurality of nozzles 46, which are adapted
to direct the high pressure fluid out of the main body 40. The
nozzles 46 can be disposed, and in one certain embodiment are
disposed, at an angle to the main body 40, so as to eject the
pressurized fluid out of the main body 40 at an angle other than 90
degrees. In other words, the fluid jet forming nozzle can be
dispose at an angle other than 90.degree. to the axis of the
cylindrical main body.
[0075] The jetting tool 14 further comprises means 48 for opening
the jetting tool 14 to fluid flow from the wellbore 10. Such fluid
opening means 48 includes a fluid-permeable plate 50, which is
mounted to the inside surface of the main body 40. The
fluid-permeable plate 50 traps a ball 52, which sits in seat 54
when the pressurized fluid is being ejected from the nozzles 46, as
shown in FIG. 4A. When the pressurized fluid is not being pumped
down the coil tubing into the jetting tool 14, the wellbore fluid
is able to be circulated up to the surface via opening means 48.
More specifically, the wellbore fluid lifts the ball 52 up against
fluid-permeable plate 50, which in turn allows the wellbore fluid
to flow up the jetting tool 14 and ultimately up through the tubing
18 to the surface, as shown in FIG. 4B. As those of ordinary skill
in the art will recognize other valves can be used in place of the
ball and seat arrangement 52 and 54 shown in FIGS. 4A and 4B.
Darts, poppets, and flappers. Furthermore, although FIGS. 4A and 4B
only show a valve at the bottom of the jetting tool 14, such valves
can be placed both at the top and the bottom, as desired.
[0076] It is to be understood, of course, that other types or
variations of jetting tools can be used, for example, the jetting
tools as described in each of U.S. Pat. Nos. 5,249,628; 5,361,856;
and 5,765,642, each of which is incorporated by reference in its
entirety.
[0077] Preferably, the step of positioning a jetting tool further
comprises accessing the wellbore with coiled tubing.
[0078] The method preferably includes the step of isolating an
interval of the wellbore in the subterranean formation, wherein the
step of positioning a jetting tool further comprises positioning
the jetting tool in the isolated interval. This allows the method
to be selectively performed in a desired interval of the wellbore
without affecting one or more other intervals of the wellbore.
[0079] The step of isolating an interval of the wellbore preferably
includes using at least one well tool to close at least one end of
the interval. The well tool for isolating an end of the interval is
preferably a drillable well tool, although a removable well tool
can be used. When a drillable well tool is used, the method
preferably further comprises the step of further comprising the
step of drilling out the drillable well tool to reopen the
wellbore. The well tool for isolating an end of the interval can
be, for example, a packer or bridge plug. The step of isolating the
interval can also be performed dynamically, e.g. using the
SurgiFrac technique to isolate the section by means of fluid
velocity as explained in U.S. Pat. No. 5,765,642, which is
incorporated by reference herein in its entirety.
[0080] The step of isolating an interval of the wellbore can employ
using an isolation fluid to close at least one end of the interval.
When an isolation fluid is used, the method preferably further
comprises the step of removing the isolation fluid to reopen the
wellbore.
[0081] For example, once the first zone 16 has been fractured, the
present invention provides for isolating the first zone 16, so that
subsequent well operations, such as the fracturing of additional
zones, can be carried out without the loss of significant amounts
of fluid. This isolation step can be carried out in a number of
ways. In one exemplary embodiment, the isolation step is carried
out by injecting into the wellbore 10 an isolation fluid, which may
have a higher viscosity than the completion fluid already in the
fracture or the wellbore.
[0082] In another exemplary embodiment, the isolation fluid is
formed of a fluid having a similar chemical makeup as the fluid
resident in the wellbore during the fracturing operation. The fluid
may have a greater viscosity than such fluid, however. In one
exemplary embodiment, the wellbore fluid is mixed with a solid
material to form the isolation fluid. The solid material may
include natural and man-made proppant agents, such as silica,
ceramics, and bauxites, or any such material that has an external
coating of any type. Alternatively, the solid (or semi-solid)
material may include paraffin, encapsulated acid or other chemical,
or resin beads.
[0083] In another exemplary embodiment, the isolation fluid is
formed of a highly viscous material, such as a gel or cross-linked
gel. Examples of gels that can be used as the isolation fluid
include, but are not limited to, fluids with high concentration of
gels such as Xanthan. Examples of cross-linked gels that can be
used as the isolation fluid include, but are not limited to, high
concentration gels such as Halliburton's DELTA FRAC fluids or K-MAX
fluids. "Heavy crosslinked gels" could also be used by mixing the
crosslinked gels with delayed chemical breakers, encapsulated
chemical breakers, which will later reduce the viscosity, or with a
material such as PLA (poly-lactic acid) beads, which although being
a solid material, with time decomposes into acid, which will
liquefy the K-MAX fluids or other crosslinked gels.
[0084] According to one aspect of the invention, the step of
delivering a curable composition through the jetting tool and to
the formation preferably further comprises filling the wellbore
interval under sufficient pressure to force the curable composition
into the formation. In this embodiment, the curable composition is
delivered at a relatively slow rate through the jetting tool to
merely fill the interval surrounding the jetting tool and form a
bullhead. For example, the delivery rate would typically be less
than about 2 barrels per minute.
[0085] According to another aspect of the invention, the step of
delivering a curable composition through the jetting tool and to
the formation further comprises delivering the curable composition
through the jetting tool under conditions sufficient to direct and
pressure the curable composition into the formation. In this
embodiment, the curable composition is delivered through the
jetting tool at a sufficient rate that may form a jet. Preferably,
however, the step of delivering a curable composition through the
jetting tool and to the formation further comprises delivering the
curable composition into the formation under conditions that are
not sufficient to initiate a fracture in the formation. If desired,
however, the curable composition can be injected through the
jetting tool under sufficient conditions to form a jet and fracture
the formation.
[0086] According to yet another aspect of the invention, the method
further comprises the step of injecting a fracturing fluid through
the jetting tool under conditions sufficient to erode a portion of
the wall of the well bore and to initiate at least one fracture
extending into the formation. The method can further comprise the
step of moving the jetting tool axially and/or rotationally during
the step of injecting a fracturing fluid through the jetting tool
to initiate at least one fracture so as to thereby erode a straight
or helical slot in a portion of the wall of the well bore.
[0087] Preferably, the step of injecting a fracturing fluid through
the jetting tool to initiate at least one fracture is separate from
the step of delivering a curable composition through the jetting
tool and to the formation, and wherein the fracturing fluid is
different than the curable composition. Preferably, the method
includes performing the step of injecting a fracturing fluid
through the jetting tool to initiate at least one fracture before
performing the step of delivering a curable composition through the
jetting tool and to the formation.
[0088] During at least part of the step of injecting a fracturing
fluid through the jetting tool, the fracturing fluid preferably
comprises a base fluid and a particulate material. Preferably, the
viscosity of the curable composition is less than the viscosity of
the base fluid. Whereas the curable composition preferably has a
relatively low viscosity to allow it to move more easily into the
formation rock, i.e., into and through the porosity of the
formation, the base fluid of a fracturing fluid preferably has a
relatively high viscosity to help suspend and carry the proppant
into a fracture without prematurely settling out of the fluid. For
example, the base fluid can be a gelled fluid and the particulate
can be sand. A typical base fluid has an apparent viscosity of
great than about 2,000 centipoise.
[0089] The method preferably further comprises the step of
injecting a fracturing fluid down the annulus under conditions to
sufficiently raise the fluid pressure in the annulus to extend the
at least one fracture initiated by the step of injecting a
fracturing fluid through the jetting tool. During at least part of
the step of injecting a fracturing fluid down the annulus, the
fracturing fluid preferably comprises a base fluid and a
particulate material. The base fluid has high viscosity to help
suspend and carry the proppant into a fracture without prematurely
settling out of the fluid.
[0090] Preferably, the proppant is coated with a curable
composition. Preferably, the curable composition that is used for
this step of depositing a proppant coated with a curable
composition into the fracture in the formation is a hardenable
resin composition. If desired, and as may be preferably in certain
formations containing fines, however, the proppant can be coated
with a tackifying composition. It is to be understood that if
desired, a portion of the proppant used in the methods according to
the invention can be coated with a hardenable resin composition and
another portion of the proppant can be coated with a tackifying
composition.
[0091] When a hardenable resin composition is used to coat the
proppant, the method of the invention preferably further comprises
the step of allowing or causing the hardenable resin composition to
harden before performing the step of flowing back or producing
fluid from the formation. For a self-hardening resin composition,
the time required for hardening will depend on the temperature of
the formation. Other hardenable resin compositions may require an
overflush with a fluid containing an appropriate catalyst to cause
the hardenable resin composition to harden.
[0092] The curable composition that is used for the step of
depositing a proppant coated with a curable composition into the
fracture in the formation should have a sufficiently high viscosity
to form a coating on the proppant.
[0093] In the case of practicing the method in a cased or lined
wellbore, the method can further comprise the step of perforating
the casing or lining. Preferably, the jetting tool is used to
perforate the casing or liner. For example, for a cased or lined
wellbore, the method preferably further comprises the step of
injecting a perforating fluid through the jetting tool under
conditions sufficient to erode a portion of the wall of the casing
or liner to form at least one perforation in the cased or lined
wellbore before the step of delivering a curable composition
through the jetting tool and to the formation. In such a case, the
method preferably further comprises the step of injecting a
fracturing fluid through the jetting tool and through the
perforation under conditions sufficient to erode the wall of the
well bore outside the casing or liner and to initiate at least one
fracture in the formation. Although these steps can be practiced at
the same time, the step of injecting a perforating fluid can be
separate from the step of injecting a fracturing fluid, and the
perforating fluid is not necessarily the same as the fracturing
fluid.
[0094] The method according to the invention can optionally further
comprise the step of overflushing the curable composition in the
formation with an overflush fluid capable of displacing at least
some of the curable composition farther out into the formation.
This is particularly advantageous where it is desired to modify the
permeability of the consolidated formation relative to that which
would be obtained without the overflush. The overflush fluid is
preferably an aqueous solution. The step of overflushing the
curable composition further comprises: delivering the overflush
fluid through the jetting tool and to the formation under
conditions that are not sufficient to initiate a fracture in the
formation. There may be some overlap in the introduction of
overflush fluid and the curable composition, for example, in cases
where separate pumping devices are used.
[0095] Preferably, the overflush fluid is placed into the formation
at a matrix flow rate such that the low-viscosity resin is
displaced from the channels, but is not displaced from its desired
location between the formation sand particles. Generally, the
volume of after-flush fluid placed in the subterranean formation
ranges from about 0.1 to about 50 times the volume of the
low-viscosity curable composition. In some embodiments of the
present invention, the volume of overflush fluid placed in the
subterranean formation ranges from about 2 to about 5 times the
volume of the low-viscosity curable composition.
[0096] The method according to the invention preferably further
comprise the step of flowing back or producing fluid from the
formation. The method preferably further comprises the step of
allowing or causing the curable composition to cure before
performing the step of flowing back or producing fluid from the
formation.
[0097] It is to be understood that the various steps according to
preferred methods of the invention can be advantageously practiced
in various combinations. It is also to be understood that the steps
according to the invention and various preferred embodiments of the
invention can be repeated at different intervals of the same
wellbore.
EXAMPLES
[0098] An example of the steps of a method according to the
invention include: for a wellbore penetrating a weakly consolidated
or unconsolidated formation, isolating an interval of a wellbore
from at least one other interval, for example, with at least one
removable or drillable packer or with a removable or drillable
bridge plug; accessing the isolated interval with tubing,
preferably with coiled tubing, to position a jetting tool in the
isolated interval; delivering a hardenable resin composition
through the jetting tool while filling the wellbore interval and
forming a bullhead of the hardenable resin composition; optionally
allowing or causing the hardenable resin composition to harden to
form a consolidated mass; injecting a fracturing fluid through the
jetting tool under conditions sufficient to form at least one slot
and to initiate a fracture in the formation; depositing a proppant
coated with a hardenable resin composition in the generated
fracture; optionally allowing or causing the coated proppant to
harden into a consolidated mass; removing or drilling out the
packer or bridge plug; and producing hydrocarbon from the
formation.
[0099] Another, more preferred example of the steps of a method
according to the invention include: for a wellbore penetrating a
weakly consolidated or unconsolidated formation, isolating an
interval of a wellbore from at least one other interval, for
example, with at least one removable or drillable packer or with a
removable or drillable bridge plug; accessing the isolated interval
with tubing, preferably with coiled tubing, to position a jetting
tool in the isolated interval; injecting a fracturing fluid through
the jetting tool under conditions sufficient to form at least one
slot and to initiate a fracture in the formation; depositing a
proppant into the fracture; delivering a hardenable resin
composition through the jetting tool while filling the wellbore
interval and forming a bullhead of the hardenable resin
composition; optionally allowing or causing the hardenable resin
composition to harden to form a consolidated mass; removing or
drilling out the packer or bridge plug; and producing hydrocarbon
from the formation.
[0100] Thus, the present invention is well adapted to carry out the
objects and attain the ends and advantages mentioned above as well
as those inherent therein. While preferred embodiments of the
invention have been described for the purpose of this disclosure,
changes in the construction and arrangement of parts and the
performance of steps can be made by those skilled in the art, which
changes are encompassed within the spirit of this invention as
defined by the appended claims.
* * * * *