U.S. patent application number 13/477658 was filed with the patent office on 2013-11-28 for enhancing the conductivity of propped fractures.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is Philip D. Nguyen, Richard D. Rickman, Jimmie D. Weaver. Invention is credited to Philip D. Nguyen, Richard D. Rickman, Jimmie D. Weaver.
Application Number | 20130312962 13/477658 |
Document ID | / |
Family ID | 48538072 |
Filed Date | 2013-11-28 |
United States Patent
Application |
20130312962 |
Kind Code |
A1 |
Weaver; Jimmie D. ; et
al. |
November 28, 2013 |
Enhancing the Conductivity of Propped Fractures
Abstract
Methods for enhancing the conductivity of propped fractures in
subterranean formations may involve using a tackifier to minimize
particulate settling during particulate placement operations in
subterranean formations. For example, methods may involve
introducing a first treatment fluid into a wellbore extending into
a subterranean formation at a pressure sufficient to create or
extend at least one fracture in the subterranean formation; and
introducing a second treatment fluid into the wellbore at a
pressure sufficient to maintain or extend the fracture in the
subterranean formation. The first treatment fluid may include at
least a first aqueous base fluid and a tackifier. The second
treatment fluid may include at least a second aqueous base fluid
and a proppant particle.
Inventors: |
Weaver; Jimmie D.; (Duncan,
OK) ; Rickman; Richard D.; (Duncan, OK) ;
Nguyen; Philip D.; (Duncan, OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Weaver; Jimmie D.
Rickman; Richard D.
Nguyen; Philip D. |
Duncan
Duncan
Duncan |
OK
OK
OK |
US
US
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
48538072 |
Appl. No.: |
13/477658 |
Filed: |
May 22, 2012 |
Current U.S.
Class: |
166/280.1 ;
166/369 |
Current CPC
Class: |
C09K 8/68 20130101; C09K
8/805 20130101; C09K 2208/08 20130101 |
Class at
Publication: |
166/280.1 ;
166/369 |
International
Class: |
E21B 43/267 20060101
E21B043/267; E21B 43/00 20060101 E21B043/00 |
Claims
1. A method comprising: introducing a first treatment fluid into a
wellbore extending into a subterranean formation at a pressure
sufficient to create or extend at least one fracture in the
subterranean formation, the first treatment fluid comprising a
first aqueous base fluid and a tackifier, wherein the first
treatment fluid causes at least a portion of a fracture face to
become tacky; and introducing a second treatment fluid into the
wellbore at a pressure sufficient to maintain or extend the
fracture in the subterranean formation, the second treatment fluid
comprising a second aqueous base fluid and a proppant particle.
2. The method of claim 1, wherein the second treatment fluid
further comprises a second tackifier.
3. The method of claim 2, wherein the first tackifier and the
second tackifier are the same but at different concentrations in
the first treatment fluid and the second treatment fluid,
respectively.
4. The method of claim 1, wherein the second treatment fluid
further comprises a fiber.
5. The method of claim 1, wherein the proppant particle has a
coating that comprises at least one selected from the group
consisting of the tackifier, a second tackifier, a compound capable
of binding to the tackifier, and any combination thereof.
6. The method of claim 1, wherein the first treatment fluid further
comprises a second proppant particle and wherein the proppant
particle has a coating that comprises at least one selected from
the group consisting of the tackifier, a second tackifier, a
compound capable of binding to the tackifier, and any combination
thereof.
7. The method of claim 1, wherein the proppant particle is coated
with a second tackifier and forms proppant aggregates or
clusters.
8. The method of claim 1, wherein the proppant particle is at least
partially degradable.
9. The method of claim 1, wherein at least a portion of the
wellbore is in excess of about 55-degrees from a vertical
inclination.
10. The method of claim 1 further comprising: producing
hydrocarbons from the subterranean formation.
11. A method comprising: introducing a first treatment fluid into a
subterranean formation at a pressure sufficient to create or extend
at least one fracture, the first treatment fluid comprising a first
aqueous base fluid, a tackifier, and a first proppant particle,
wherein the first treatment fluid causes at least a portion of a
fracture face to become tacky; and introducing a second treatment
fluid into the subterranean formation at a pressure sufficient to
maintain or extend the fracture, the second treatment fluid
comprising a second aqueous base fluid and a second proppant
particle.
12. The method of claim 11, wherein the first and/or second
proppant particle has a coating that comprises at least one
selected from the group consisting of the tackifier, a second
tackifier, a compound capable of binding to the tackifier, and any
combination thereof.
13. The method of claim 11, wherein the first and/or second
proppant particle is at least partially degradable.
14. The method of claim 11, wherein at least a portion of the
wellbore is in excess of about 55-degrees from a vertical
inclination.
15. A method comprising: introducing a treatment fluid into a
subterranean formation via a high rate water pack operation so as
to create or extend at least one fracture, the treatment fluid
comprising a tackifier and a low-viscosity carrier fluid; and
wherein the treatment fluid causes at least a portion of a fracture
face to become tacky.
16. The method of claim 15, wherein the treatment fluid further
comprises a proppant particle.
17. The method of claim 16, wherein the treatment fluid further
comprises a fiber.
18. The method of claim 16, wherein the proppant particle has a
coating that comprises at least one selected from the group
consisting of the tackifier, a second tackifier, a compound capable
of binding to the tackifier, and any combination thereof.
19. The method of claim 15 further comprising: introducing a second
treatment fluid into the subterranean formation at a pressure
sufficient to maintain or extend the fracture, the second treatment
fluid comprising a second low-viscosity carrier fluid and a
proppant particle.
20. The method of claim 19, wherein the second treatment fluid
further comprises a third tackifier.
Description
BACKGROUND
[0001] The present invention relates to methods for enhancing the
conductivity of propped fractures in subterranean formations.
[0002] After a wellbore is drilled, it may often be necessary to
fracture the subterranean formation to enhance hydrocarbon
production, especially in tight formations like shales and
tight-gas sands. Access to the subterranean formation can be
achieved by first creating an access conduit from the wellbore to
the subterranean formation. Then, a fracturing fluid, often called
a pad, is introduced at pressures exceeding those required to
maintain matrix flow in the formation permeability to create or
enhance at least one fracture that propagates from at least one
access conduit. The pad fluid is followed by a proppant slurry
fluid comprising a proppant particle to prop the fracture open
after pressure from the fluid is reduced. The proppant particles
hold open the fractures thereby maintaining the ability for fluid
to flow through the fracture and ultimately be produced at the
surface. However, as proppant particles are suspended in treatment
fluids, gravity can cause the proppant particles to settle and form
dunes.
[0003] As used herein, "proppant particles" and "proppants" may be
used interchangeable and refer to any material or formulation that
can be used to hold open at least a portion of a fracture. As used
herein, a "proppant pack" is the collection of proppant particles
in a fracture. It should be understood that the term "particulate"
or "particle," and derivatives thereof as used in this disclosure,
includes all known shapes of materials, including substantially
spherical materials, low to high aspect ratio materials, fibrous
materials, polygonal materials (such as cubic materials), and
mixtures thereof.
[0004] Proppant settling can be particularly prevalent in high-rate
water fracturing operations and in deviated wellbores. In high-rate
water fracturing, the rate of water flow helps suspend and carry
proppant particles to desired locations with the subterranean
formation. As there are traditionally minimal suspending agents in
high-rage water fracturing fluids, once the high-rate water flow
subsides, the proppant tends to settle and form dunes of proppant
particles within fractures. An illustrative example of a dunned
proppant pack as compared to an idealized homogeneous proppant pack
are provided in FIGS. 1A-B, respectively.
[0005] Proppant settling in deviated wellbores can also be
problematic because the fractures radiating from deviated wellbores
tend to have angles closer to vertical where proppant particles
settle either back down to the wellbore or into those fractures
radiating down from the wellbore. As used herein, the term
"deviated wellbore" refers to a wellbore in which any portion of
the well is in excess of about 55-degrees from a vertical
inclination.
[0006] Heterogeneous proppant packs, e.g., duned or settled
proppant packs, may have less strength to hold open fractures than
a more homogeneously disperse proppant pack. Weaker proppant packs
can lead to partial to total fracture collapse, thereby reducing
the access to the subterranean formation and consequently reducing
hydrocarbon production. To remedy or mitigate against the weaker
proppant packs, more proppant can be introduced into the fractures.
However, the costs associated with transportation of the extra
proppant particle to the well site and additional time for
fracturing and propping operations can become excessive.
SUMMARY OF THE INVENTION
[0007] The present invention relates to methods for enhancing the
conductivity of propped fractures in subterranean formations.
[0008] Some embodiments of the present invention may involve
introducing a first treatment fluid into a wellbore extending into
a subterranean formation at a pressure sufficient to create or
extend at least one fracture in the subterranean formation; and
introducing a second treatment fluid into the wellbore at a
pressure sufficient to maintain or extend the fracture in the
subterranean formation. The first treatment fluid may include at
least a first aqueous base fluid and a tackifier and may cause at
least a portion of a fracture face to become tacky. The second
treatment fluid may include at least a second aqueous base fluid
and a proppant particle.
[0009] Other embodiments of the present invention may involve
introducing a first treatment fluid into a subterranean formation
at a pressure sufficient to create or extend at least one fracture;
and introducing a second treatment fluid into the subterranean
formation at a pressure sufficient to maintain or extend the
fracture. The first treatment fluid may include at least a first
aqueous base fluid, a tackifier, and a first proppant particle and
may cause at least a portion of a fracture face to become tacky.
The second treatment fluid may include at least a second aqueous
base fluid and a second proppant particle.
[0010] Yet other embodiments of the present invention may involve
introducing a treatment fluid into a subterranean formation via a
high rate water pack operation so as to create or extend at least
one fracture. The treatment fluid may include at least a tackifier
and a low-viscosity carrier fluid and may cause at least a portion
of a fracture face to become tacky.
[0011] The features and advantages of the present invention will be
readily apparent to those skilled in the art upon a reading of the
description of the preferred embodiments that follows.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] The following figures are included to illustrate certain
aspects of the present invention, and should not be viewed as
exclusive embodiments. The subject matter disclosed is capable of
considerable modifications, alterations, combinations, and
equivalents in form and function, as will occur to those skilled in
the art and having the benefit of this disclosure.
[0013] FIG. 1A provides an illustration of a dunned proppant pack
in a subterranean fracture:
[0014] FIG. 1B provides an illustration of an idealized proppant
pack and a subterranean fracture.
[0015] FIGS. 2A-C provide SEM images parallel to the bedding planes
of tackified shale after exposure to the proppant particles.
[0016] FIGS. 3A-C provide SEM images perpendicular to the bedding
planes of tackified shale after exposure to the proppant
particles.
DETAILED DESCRIPTION
[0017] The present invention relates to methods for enhancing the
conductivity of propped fractures in subterranean formations.
[0018] The methods of the present invention may, in some
embodiments, advantageously provide for proppant packs with less
settling, which may be especially advantageous when used in
conjunction with high rate water packs and deviated wellbores. In
some embodiments, treatment fluids comprising tackifier may be used
so as to render the fracture faces tacky. Tacky fracture faces may
advantageously enable proppant particulates to stick thereto,
thereby minimizing proppant settling. Introduction of a tackifier
during a fracturing operation may advantageously expose more
fracture faces to the tackifier, which enhances the surface area to
which proppant may adhere. Further, proppant particles may in some
embodiments have a coating that enhances adhesion to a tacky
fracture face and/or other proppant particles. In some embodiments,
proppant particles coated with a tackifier may form aggregates
and/or clusters of proppant particles. As used herein, the term
"coating," and the like, does not imply any particular degree of
coating on a surface (e.g., a fracture face and/or a proppant
particle). In particular, the terms "coat" or "coating" do not
imply 100% coverage by the coating on a surface.
[0019] Minimizing proppant settling may advantageously provide for
more homogeneous proppant packs, which may yield stronger proppant
packs and proppant packs capable of producing more
hydrocarbons.
[0020] While methods of the present invention may advantageously be
employed in wellbores more susceptible to proppant settling, e.g.,
deviated versus vertical wellbores, it should be understood that
the methods provided herein are applicable to wellbores at any
angle including, but not limited to, vertical wellbores, deviated
wellbores, highly deviated wellbores, horizontal wellbores, and
hybrid wellbores comprising sections of any combination of the
aforementioned wells. In some embodiments, a subterranean formation
and wellbore may be provided with an existing fracture network. As
used herein, the term "deviated wellbore" refers to a wellbore in
which any portion of the well is in excess of about 55-degrees from
a vertical inclination. As used herein, the term "highly deviated
wellbore" refers to a wellbore that is oriented between 75-degrees
and 125-degrees off-vertical.
[0021] Further, while any subterranean formation capable of being
fractured and susceptible to proppant settling may be used in
conjunction with the present invention, subterranean formations
that may benefit from these methods may include unconventional
formations, e.g., low-permeability tight formations, shales,
sandstone, coal-bed methane wells, and the like. By way of
nonlimiting example, tight formations and shales with low
permeabilities can have a slow fracture closure rate, which may
allow the proppant time to settle. Consequently, high flow
velocities are often used to keep the proppant to suspend during
pumping. Once placed inside the created fracture, low flow rate and
insufficient proppant suspension capability of the carrier fluid
often result in quick settling of proppant to the lower portion of
the fracture. Fractures or portions of fractures not having
proppant to keep them open will often close, thereby reducing
access to hydrocarbons and consequently reducing well
productivity.
[0022] It should be noted that when "about" is provided at the
beginning of a numerical list, "about" modifies each number of the
numerical list. It should be noted that in some numerical listings
of ranges, some lower limits listed may be greater than some upper
limits listed. One skilled in the art will recognize that the
selected subset will require the selection of an upper limit in
excess of the selected lower limit.
[0023] Some embodiments of the present invention may involve
introducing a treatment fluid into a subterranean formation, where
the treatment fluid comprises an aqueous base fluid, a tackifier,
and optionally a proppant particle. Some embodiments of the present
invention may further involve introducing a second treatment fluid
into the subterranean formation, with the second treatment fluid
comprising an aqueous base fluid, a proppant particle, and
optionally a tackifier. Generally, the first treatment fluid
introduced into the subterranean formation may be at a pressure
sufficient to create or extend at least one fracture in the
subterranean formation, where subsequent treatment fluids that
comprise proppant particles, if used, may be introduced at pressure
sufficient to maintain or extend at least one fracture in the
subterranean formation. The first treatment fluid may
advantageously at least partially coat formation faces with
tackifier to which proppant particles may stick, thereby mitigating
dunning in proppant packs. Generally, tackifiers or tackifying
agents are compositions (e.g., polymers) that as liquids or in
solution at the temperature of the subterranean formation are, by
themselves, nonhardening.
[0024] Suitable treatment fluids for use in conjunction with
introducing tackifier resin to the subterranean formation may
include, but are not limited to, fracturing fluids, high-rate water
pack fluids, pre-pad fluids, and the like. As used herein, the
terms "high-rate water pack" ("HRWP") refer to an operation in
which particulates are injected into a cased and perforated
wellbore at a rate and/or pressure that is at or near the fracture
rate and/or pressure of the reservoir.
[0025] In some embodiments where a high-rate water pack is
employed, the aqueous base fluid may be characterized as a low
viscosity carrier fluid. The term "low-viscosity carrier fluid," as
used herein, refers to a fluid having a viscosity of less than
about 20 cp, preferably less than about 10 cp. By way of example, a
solution of 10 pounds of guar in 1000 gallons of water solution is
a typical low-viscosity carrier fluid.
[0026] In some embodiments, a proppant particle may be at least
partially coated with a tackifier. In some embodiments, coating the
proppant particle with a tackifier may enable proppant particles to
adhere to each other in a proppant pack. Adhesion of proppant
particles to each other, in some embodiments, may be advantageous
in larger fractures where not all proppant particles will be in
contact with a fracture face. It should be noted, that unless
otherwise specified proppant particles discussed herein may be
coated or uncoated.
[0027] In some embodiments, a proppant particle may be at least
partially coated with a compound that readily binds to a tackifier
on the fracture face. Coating proppant particles with such a
compound may enhance, in some embodiments, the adhesion of a
proppant particle to a fracture face and/or an adjacent proppant
particle. Suitable compounds that readily bind to a tackifier on
the fracture face may include, but are not limited to, polymers
having a charge opposite of the tackifier, e.g., a cationic
tackifier and an anionic polymer, or an anionic tackifier and a
cationic polymer.
[0028] Some embodiments of the present invention may involve
introducing a first treatment fluid comprising a tackifier, an
aqueous base fluid, and a proppant particle at a pressure
sufficient to create or extend at least one fracture, and then
introducing a second treatment fluid comprising a coated proppant
particle. Suitable proppant coatings may include, but are not
limited to, tackifiers, resins, any compound that readily binds to
a tackifier (e.g., to a tackifier on a fracture face and/or on a
proppant particle), or any combination thereof.
[0029] Before performing fracturing and propping operations
described herein, some embodiments may involve treating the
subterranean formation. After fracturing and propping operations
described herein are complete, some embodiments may involve
treating the subterranean formation. Suitable treatment operations
before and/or after fracturing and propping operations described
herein may include, but are not limited to, lost circulation
operations, stimulation operations, sand control operations,
completion operations, acidizing operations, scale inhibiting
operations, water-blocking operations, clay stabilizer operations,
gravel packing operations, wellbore strengthening operations, sag
control operations, and production operations (e.g., producing
hydrocarbons from the wellbore). The methods and compositions of
the present invention may be used in full-scale operations or
pills. As used herein, a "pill" is a type of relatively small
volume of specially prepared treatment fluid placed or circulated
in the wellbore. By way of nonlimiting example, a formation may
receive an acidizing operation prior to fracturing and propping
operations described herein. By way of another nonlimiting example,
a formation may receive clay stabilizing operations prior to and/or
after fracturing and propping operations described herein. By way
of yet another nonlimiting example, a formation may receive a scale
inhibiting operation after fracturing and propping operations
described herein. One skilled in the art with the benefit of this
disclosure should understand the plurality of combinations of
operations that may be performed before and/or after fracturing and
propping operations described herein.
[0030] In some embodiments, a treatment fluid for use in
conjunction with the present invention may comprise an aqueous base
fluid, a tackifier, and optionally proppant particles.
[0031] Aqueous base fluids suitable for use in the treatment fluids
of the present invention may comprise fresh water, saltwater (e.g.,
water containing one or more salts dissolved therein), brine (e.g.,
saturated salt water or produced water), seawater, produced water
(e.g., water produced from a subterranean formation),
aqueous-miscible fluids, or combinations thereof. Generally, the
water may be from any source, provided that it does not contain
components that might adversely affect the stability and/or
performance of the first treatment fluids or second treatment
fluids of the present invention. In certain embodiments, the
density of the aqueous base fluid can be adjusted, among other
purposes, to provide additional particulate transport and
suspension in the treatment fluids used in the methods of the
present invention. In certain embodiments, the pH of the aqueous
base fluid may be adjusted (e.g., by a buffer or other pH adjusting
agent), among other purposes, to activate a crosslinking agent
and/or to reduce the viscosity of the first treatment fluid (e.g.,
activate a breaker, deactivate a crosslinking agent). In these
embodiments, the pH may be adjusted to a specific level, which may
depend on, among other factors, the types of gelling agents, acids,
and other additives included in the treatment fluid. One of
ordinary skill in the art, with the benefit of this disclosure,
will recognize when such density and/or pH adjustments are
appropriate.
[0032] Suitable aqueous-miscible fluids may include, but not be
limited to, alcohols, e.g., methanol, ethanol, n-propanol,
isopropanol, n-butanol, sec-butanol, isobutanol, and t-butanol;
glycerins; glycols, e.g., polyglycols, propylene glycol, and
ethylene glycol; polyglycol amines; polyols; any derivative
thereof; any in combination with salts, e.g., sodium chloride,
calcium chloride, calcium bromide, zinc bromide, potassium
carbonate, sodium formate, potassium formate, cesium formate,
sodium acetate, potassium acetate, calcium acetate, ammonium
acetate, ammonium chloride, ammonium bromide, sodium nitrate,
potassium nitrate, ammonium nitrate, ammonium sulfate, calcium
nitrate, sodium carbonate, and potassium carbonate; any in
combination with an aqueous-based fluid, and any combination
thereof.
[0033] In some embodiments, a treatment fluid may be foamed or a
wet gas. Foamed fluids and wet gases may minimize the exposure of
the subterranean formation to aqueous-based fluid, which for some
tight formations like shale advantageously minimize the deleterious
effects water has on the fracture faces (e.g., clay swelling).
Foamed fluids and wet gases may also, in some embodiments, be
capable of suspending the small propping agents because of their
size.
[0034] In some embodiments, a treatment fluid for use in
conjunction with the present invention may comprise an aqueous base
fluid, a tackifier, a gas, a foaming agent, and optionally
proppant'particles.
[0035] A suitable gas for use in conjunction with the present
invention may include, but is not limited to, nitrogen, carbon
dioxide, air, methane, helium, argon, and any combination thereof.
One skilled in the art, with the benefit of this disclosure, should
understand the benefit of each gas. By way of nonlimiting example,
carbon dioxide foams may have deeper well capability than nitrogen
foams because carbon dioxide emulsions have greater density than
nitrogen gas foams so that the surface pumping pressure required to
reach a corresponding depth is lower with carbon dioxide than with
nitrogen. Moreover, the higher density may impart greater proppant
transport capability, up to about 12 lb of proppant per gal of
fracture fluid.
[0036] In some embodiments, the quality of the foamed treatment
fluid may range from a lower limit of about 5%, 10%, 25%, 40%, 50%,
60%, or 70% gas volume to an upper limit of about 95%, 90%, 80%,
75%, 60%, or 50% gas volume, and wherein the quality of the foamed
treatment fluid may range from any lower limit to any upper limit
and encompass any subset therebetween. Most preferably, the foamed
treatment fluid may have a foam quality from about 85% to about
95%, or about 90% to about 95%.
[0037] Suitable foaming agents for use in conjunction with the
present invention may include, but are not limited to, cationic
foaming agents, anionic foaming agents, amphoteric foaming agents,
nonionic foaming agents, or any combination thereof. Nonlimiting
examples of suitable foaming agents may include, but are not
limited to, surfactants like betaines, sulfated or sulfonated
alkoxylates, alkyl quarternary amines, alkoxylated linear alcohols,
alkyl sulfonates, alkyl aryl sulfonates, C.sub.10-C.sub.20
alkyldiphenyl ether sulfonates, polyethylene glycols, ethers of
alkylated phenol, sodium dodecylsulfate, alpha olefin sulfonates
such as sodium dodecane sulfonate, trimethyl hexadecyl ammonium
bromide, and the like, any derivative thereof, or any combination
thereof. Foaming agents may be included in foamed treatment fluids
at concentrations ranging typically from about 0.05% to about 2% of
the liquid component by weight (e.g., from about 0.5 to about 20
gallons per 1000 gallons of liquid).
[0038] Suitable tackifiers for use in conjunction with the present
invention may include, but are not limited to, aqueous tackifying
agents, non-aqueous tackifying agents, tackifier emulsions,
aggregating compositions, or any combination thereof. Aqueous
tackifying agents suitable for use in the present invention are
usually not generally significantly tacky when placed onto a
particulate, but are capable of being "activated" (e.g.,
destabilized, coalesced and/or reacted) to transform the compound
into a sticky, tackifying compound at a desirable time. Such
activation may occur before, during, or after the aqueous tackifier
agent is placed in the subterranean formation. In some embodiments,
a pretreatment may be first contacted with the surface of a
particulate to prepare it to be coated with an aqueous tackifier
agent. Suitable aqueous tackifying agents are generally charged
polymers that comprise compounds that, when in an aqueous solvent
or solution, will form a nonhardening coating (by itself or with an
activator) and, when placed on a particulate, will increase the
continuous critical resuspension velocity of the particulate when
contacted by a stream of water. The aqueous tackifier agent may
enhance the grain-to-grain contact between the individual
particulates within the formation (be they proppant particulates,
formation fines, or other particulates), helping bring about the
consolidation of the particulates into a cohesive, flexible, and
permeable mass.
[0039] Suitable aqueous tackifying agents include any polymer that
can bind, coagulate, or flocculate a particulate. Also, polymers
that function as pressure-sensitive adhesives may be suitable.
Examples of aqueous tackifying agents suitable for use in the
present invention include, but are not limited to acrylic acid
polymers; acrylic acid ester polymers; acrylic acid derivative
polymers; acrylic acid homopolymers; acrylic acid ester
homopolymers (such as poly(methyl acrylate), poly(butyl acrylate),
and poly(2-ethylhexyl acrylate)); acrylic acid ester co-polymers;
methacrylic acid derivative polymers; methacrylic acid
homopolymers; methacrylic acid ester homopolymers (such as
poly(methyl methacrylate), poly(butyl methacrylate), and
poly(2-ethylhexyl methacrylate)); acrylamido-methyl-propane
sulfonate polymers; acrylamido-methyl-propane sulfonate derivative
polymers; acrylamido-methyl-propane sulfonate co-polymers; and
acrylic acid/acrylamido-methyl-propane sulfonate co-polymers;
derivatives thereof, and combinations thereof. Methods of
determining suitable aqueous tackifying agents and additional
disclosure on aqueous tackifying agents can be found in U.S. Patent
Publication No. 2005/0277554 filed Jun. 9, 2004 and U.S. Patent
Publication No. 2005/0274517 filed Jun. 9, 2004, the entire
disclosures of which are hereby incorporated by reference.
[0040] Some suitable tackifying agents are described in U.S. Pat.
No. 5,249,627 by Harms, et al., the entire disclosure of which is
incorporated by reference, which discloses aqueous tackifying
agents that comprise at least one member selected from the group
consisting of benzyl coco di-(hydroxyethyl) quaternary amine,
p-T-amyl-phenol condensed with formaldehyde, and a copolymer
comprising from about 80% to about 100% C1-30 alkylmethacrylate
monomers and from about 0% to about 20% hydrophilic monomers. In
some embodiments, the aqueous tackifying agent may comprise a
copolymer that comprises from about 90% to about 99.5%
2-ethylhexylacrylate and from about 0.5% to about 10% acrylic acid.
Suitable hydrophillic monomers may be any monomer that will provide
polar oxygen-containing or nitrogen-containing groups. Suitable
hydrophillic monomers include dialkyl amino alkyl(meth)acrylates
and their quaternary addition and acid salts, acrylamide,
N-(dialkyl amino alkyl)acrylamide, methacrylamides and their
quaternary addition and acid salts, hydroxy alkyl(meth)acrylates,
unsaturated carboxylic acids such as methacrylic acid or acrylic
acid, hydroxyethyl acrylate, acrylamide, and the like. Combinations
of these may be suitable as well. These copolymers can be made by
any suitable emulsion polymerization technique. Methods of
producing these copolymers are disclosed, for example, in U.S. Pat.
No. 4,670,501 by Dymond, et al., the entire disclosure of which is
incorporated herein by reference.
[0041] Additional tackifiers may include silyl-modified polyamide
compounds, which may be described as substantially self-hardening
compositions that are capable of at least partially adhering to
particulates in the unhardened state, and that are further capable
of self-hardening themselves to a substantially non-tacky state to
which individual particulates such as formation fines will not
adhere to, for example, in formation or proppant pack pore throats.
Such silyl-modified polyamides may be based, for example, on the
reaction product of a silating compound with a polyamide or a
combination of polyamides. The polyamide or combination of
polyamides may be one or more polyamide intermediate compounds
obtained, for example, from the reaction of a polyacid (e.g.,
diacid or higher) with a polyamine (e.g., diamine or higher) to
form a polyamide polymer with the elimination of water. Other
suitable silyl-modified polyamides and methods of making such
compounds are described in U.S. Pat. No. 6,439,309 by Matherly, et
al., the relevant disclosure of which is herein incorporated by
reference.
[0042] In some embodiments, a tackifier for use in conjunction with
the present invention may include an emulsified tackifier. The
tackifier in suitable emulsions may include a non-aqueous
tackifying agent. These consolidating agent emulsions have an
aqueous external phase, organic-based internal phase, and an
emulsifying agent.
[0043] Suitable tackifier emulsions may comprise an aqueous
external phase comprising an aqueous fluid in an amount in the
range of about 20% to 99.9% by weight of the tackifier emulsion
composition, or more preferably about 60% to 99.9% by weight of the
tackifier emulsion composition, or most preferably about 95% to
99.9% by weight of the tackifier emulsion composition.
[0044] Further, suitable tackifier emulsions may comprise a
nonaqueous tackifier in an amount in the range of about 0.1% to
about 80% by weight of the tackifier emulsion composition, or more
preferably about 0.1% to about 40% by weight of the tackifier
emulsion composition, or most preferably about 0.1% to about 5% by
weight of the tackifier emulsion composition.
[0045] Suitable emulsifying agents for use in conjunction with the
tackifier emulsion composition may include, but are not limited to,
surfactants, proteins, hydrolyzed proteins, lipids, glycolipids,
nanosized particulates (e.g., fumed silica), or any combination
thereof.
[0046] Suitable non-aqueous tackifying agents may include, but are
not limited to, polyamides that are liquids or in solution at the
temperature of the subterranean formation such that they are, by
themselves, non-hardening when introduced into the subterranean
formation; the product of a condensation reaction of a commercially
available polyamine and polyacid (e.g., dibasic acids containing
some trimer and higher oligomers, small amounts of monomer acids,
trimer acids, synthetic acids produced from fatty acids, maleic
anhydride, acrylic acid, and the like, or any combination thereof).
Additional compounds which may be used as non-aqueous tackifying
agents include liquids and solutions of, for example, polyesters,
polycarbonates, silyl-modified polyamide compounds, polycarbamates,
urethanes, natural resins such as shellac, and the like.
Combinations of any of the aforementioned non-aqueous tackifiers
may be suitable as well.
[0047] Additional details of tackifier emulsions may be found in
U.S. Pat. No. 7,819,192 by Weaver, et al., which is incorporated
herein by reference.
[0048] In some embodiments, the tackifiers may comprise an
aggregating composition which can modify the zeta potential or
aggregation potential of a particulate. Such modifications can
permit any two surfaces (e.g., of particulates, of a particulate
and a substrate, etc.) to have a greater attraction for one
another.
[0049] Aggregating compositions suitable for use in the present
invention include, but are not limited to, a reaction product of an
amine and a phosphate ester, where the aggregating composition is
designed to coat a surface with the reaction product to change the
zeta potential or aggregation potential of the surface. Suitable
aggregating compositions and their methods of use can be found in
U.S. Pat. No. 7,392,847 by Gatlin, et al., and U.S. Pat. No.
7,956,017 by Gatlin, et al., the entire disclosures of which are
hereby incorporated by reference.
[0050] Proppant particulates suitable for use in the present
invention may comprise any material suitable for use in
subterranean operations. Suitable materials for these proppant
particulates include, but are not limited to, sand, bauxite,
ceramic materials, glass materials, polymer materials,
polytetrafluoroethylene materials, nut shell pieces, cured resinous
particulates comprising nut shell pieces, seed shell pieces, cured
resinous particulates comprising seed shell pieces, fruit pit
pieces, cured resinous particulates comprising fruit pit pieces,
wood, composite particulates, and combinations thereof. Suitable
composite particulates may comprise a binder and a filler material
wherein suitable filler materials include silica, alumina, fumed
carbon, carbon black, graphite, mica, titanium dioxide, barite,
meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly
ash, hollow glass microspheres, solid glass, and combinations
thereof. Suitable proppant particles for use in conjunction with
the present invention may be any known shape of material, including
substantially spherical materials, fibrous materials, polygonal
materials (such as cubic materials), and combinations thereof.
Moreover, fibrous materials, that may or may not be used to bear
the pressure of a closed fracture, may be included in certain
embodiments of the present invention.
[0051] In some embodiments, proppant particles may be present in a
treatment fluid for use in the present invention in an amount in
the range of from about 0.1 pounds per gallon ("ppg") to about 15
ppg by volume of the treatment fluid.
[0052] In some embodiments, proppant particles may comprise
degradable materials. Degradable materials may include, but not be
limited to, dissolvable materials, materials that deform or melt
upon heating such as thermoplastic materials, hydrolytically
degradable materials, materials degradable by exposure to
radiation, materials reactive to acidic fluids, or any combination
thereof. In some embodiments, degradable materials may be degraded
by temperature, presence of moisture, oxygen, microorganisms,
enzymes, pH, free radicals, and the like. In some embodiments,
degradation may be initiated in a subsequent treatment fluid
introduced into the subterranean formation at some time when
diverting is no longer necessary. In some embodiments, degradation
may be initiated by a delayed-release acid, such as an
acid-releasing degradable material or an encapsulated acid, and
this may be included in the treatment fluid comprising the
degradable material so as to reduce the pH of the treatment fluid
at a desired time, for example, after introduction of the treatment
fluid into the subterranean formation.
[0053] In choosing the appropriate degradable material, one should
consider the degradation products that will result. Also, these
degradation products should not adversely affect other operations
or components. For example, a boric acid derivative may not be
included as a degradable material in the well drill-in and
servicing fluids of the present invention where such fluids use
guar as the viscosifier, because boric acid and guar are generally
incompatible. One of ordinary skill in the art, with the benefit of
this disclosure, will be able to recognize when potential
components of a treatment fluid of the present invention would be
incompatible or would produce degradation products that would
adversely affect other operations or components.
[0054] The degradability of a degradable polymer often depends, at
least in part, on its backbone structure. For instance, the
presence of hydrolyzable and/or oxidizable linkages in the backbone
often yields a material that will degrade as described herein. The
rates at which such polymers degrade are dependent on the type of
repetitive unit, composition, sequence, length, molecular geometry,
molecular weight, morphology (e.g., crystallinity, size of
spherulites, and orientation), hydrophilicity, hydrophobicity,
surface area, and additives. Also, the environment to which the
polymer is subjected may affect how it degrades, e.g., temperature,
presence of moisture, oxygen, microorganisms, enzymes, pH, and the
like.
[0055] Suitable examples of degradable polymers for a solid
particulate of the present invention that may be used include, but
are not limited to, polysaccharides such as cellulose; chitin;
chitosan; and proteins. Suitable examples of degradable polymers
that may be used in accordance with the present invention include,
but are not limited to, those described in the publication of
Advances in Polymer Science, Vol. 157 entitled "Degradable
Aliphatic Polyesters," edited by A. C. Albertsson, pages 1-138.
Specific examples include homopolymers, random, block, graft, and
star- and hyper-branched aliphatic polyesters. Such suitable
polymers may be prepared by polycondensation reactions,
ring-opening polymerizations, free radical polymerizations, anionic
polymerizations, carbocationic polymerizations, coordinative
ring-opening polymerizations, as well as by any other suitable
process. Examples of suitable degradable polymers that may be used
in conjunction with the methods of this invention include, but are
not limited to, aliphatic polyesters; poly(lactides);
poly(glycolides); poly(.epsilon.-caprolactones); poly(hydroxy ester
ethers); poly(hydroxybutyrates); poly(anhydrides); polycarbonates;
poly(orthoesters); poly(amino acids); poly(ethylene oxides);
poly(phosphazenes); poly(ether esters), polyester amides,
polyamides, and copolymers or blends of any of these degradable
polymers, and derivatives of these degradable polymers. The term
"copolymer" as used herein is not limited to the combination of two
polymers, but includes any combination of polymers, e.g.,
terpolymers and the like. As referred to herein, the term
"derivative" is defined herein to include any compound that is made
from one of the listed compounds, for example, by replacing one
atom in the base compound with another atom or group of atoms. Of
these suitable polymers, aliphatic polyesters such as poly(lactic
acid), poly(anhydrides), poly(orthoesters), and
poly(lactide)-co-poly(glycolide) copolymers are preferred.
Poly(lactic acid) is especially preferred. Poly(orthoesters) also
may be preferred. Other degradable polymers that are subject to
hydrolytic degradation also may be suitable. The choice may depend
on the particular application and the conditions involved. Other
guidelines to consider include the degradation products that
result, the time required for the requisite degree of degradation,
and the desired result of the degradation (e.g., voids).
[0056] Aliphatic polyesters degrade chemically, inter alia, by
hydrolytic cleavage. Hydrolysis can be catalyzed by either acids or
bases. Generally, during the hydrolysis, carboxylic end groups may
be formed during chain scission, which may enhance the rate of
further hydrolysis. This mechanism is known in the art as
"autocatalysis," and is thought to make polyester matrices more
bulk-eroding.
[0057] Suitable aliphatic polyesters have the general formula of
repeating units shown below:
##STR00001##
where n is an integer between 75 and 10,000 and R is selected from
the group consisting of hydrogen, alkyl, aryl, alkylaryl, acetyl,
heteroatoms, and mixtures thereof. In certain embodiments of the
present invention wherein an aliphatic polyester is used, the
aliphatic polyester may be poly(lactide). Poly(lactide) is
synthesized either from lactic acid by a condensation reaction or,
more commonly, by ring-opening polymerization of cyclic lactide
monomer. Since both lactic acid and lactide can achieve the same
repeating unit, the general term poly(lactic acid) as used herein
refers to writ of Formula I without any limitation as to how the
polymer was made (e.g., from lactides, lactic acid, or oligomers),
and without reference to the degree of polymerization or level of
plasticization.
[0058] The lactide monomer exists generally in three different
forms: two stereoisomers (L- and D-Iactide) and racemic D,L-lactide
(meso-lactide). The oligomers of lactic acid and the oligomers of
lactide are defined by the formula:
##STR00002##
where m is an integer in the range of from greater than or equal to
about 2 to less than or equal to about 75. In certain embodiments,
m may be an integer in the range of from greater than or equal to
about 2 to less than or equal to about 10. These limits may
correspond to number average molecular weights below about 5,400
and below about 720, respectively. The chirality of the lactide
units provides a means to adjust, inter alia, degradation rates, as
well as physical and mechanical properties. Poly(L-lactide), for
instance, is a semicrystalline polymer with a relatively slow
hydrolysis rate. This could be desirable in applications of the
present invention in which a slower degradation of the degradable
material is desired. Poly(D,L-lactide) may be a more amorphous
polymer with a resultant faster hydrolysis rate. This may be
suitable for other applications in which a more rapid degradation
may be appropriate. The stereoisomers of lactic acid may be used
individually, or may be combined in accordance with the present
invention. Additionally, they may be copolymerized with, for
example, glycolide or other monomers like E-caprolactone,
1,5-dioxepan-2-one, trimethylene carbonate, or other suitable
monomers to obtain polymers with different properties or
degradation times. Additionally, the lactic acid stereoisomers can
be modified by blending high and low molecular weight polylactide
or by blending polylactide with other polyesters. In embodiments
wherein polylactide is used as the degradable material, certain
preferred embodiments employ a mixture of the D and L
stereoisomers, designed so as to provide a desired degradation time
and/or rate. Examples of suitable sources of degradable material
are commercially available as 6250D.TM. (poly(lactic acid),
available from Cargill Dow) and 5639A.TM. (poly(lactic acid),
available from Cargill Dow).
[0059] Aliphatic polyesters useful in the present invention may be
prepared by substantially any of the conventionally known
manufacturing methods such as those described in U.S. Pat. No.
2,703,316 by Schneider; U.S. Pat. No. 3,912,692 by Casey, et al.;
U.S. Pat. No. 4,387,769 by Erbstoesser, et al.; U.S. Pat. No.
5,216,050 by Sinclair; and U.S. Pat. No. 6,323,307 by Bigg, et al.,
the relevant disclosures of which are incorporated herein by
reference.
[0060] Polyanhydrides are another type of degradable polymer that
may be suitable for use in the present invention. Polyanhydride
hydrolysis proceeds, inter alia, via free carboxylic acid
chain-ends to yield carboxylic acids as final degradation products.
Their erosion time can be varied over a broad range of changes in
the polymer backbone. Examples of suitable polyanhydrides include
poly(adipic anhydride), poly(suberic anhydride), poly(sebacic
anhydride), and poly(dodecanedioic anhydride). Other suitable
examples include, but are not limited to, poly(maleic anhydride)
and poly(benzoic anhydride).
[0061] The physical properties of degradable polymers may depend on
several factors including, but not limited to, the composition of
the repeat units, flexibility of the chain, presence of polar
groups, molecular mass, degree of branching, crystallinity, and
orientation. For example, short chain branches may reduce the
degree of crystallinity of polymers while long chain branches may
lower the melt viscosity and may impart, inter alia, extensional
viscosity with tension-stiffening behavior. The properties of the
material utilized further may be tailored by blending, and
copolymerizing it with another polymer, or by a change in the
macromolecular architecture (e.g., hyper-branched polymers,
star-shaped, or dendrimers, and the like). The properties of any
such suitable degradable polymers (e.g., hydrophobicity,
hydrophilicity, rate of degradation, and the like) can be tailored
by introducing select functional groups along the polymer chains.
For example, poly(phenyllactide) will degrade at about one-fifth of
the rate of racemic poly(lactide) at a pH of 7.4 at 55.degree. C.
One of ordinary skill in the art, with the benefit of this
disclosure, will be able to determine the appropriate functional
groups to introduce to the polymer chains to achieve the desired
physical properties of the degradable polymers.
[0062] Suitable dehydrated compounds for use as solid particulates
in the present invention may degrade over time as they are
rehydrated. For example, a particulate solid anhydrous borate
material that degrades over time may be suitable for use in the
present invention. Specific examples of particulate solid anhydrous
borate materials that may be used include, but are not limited to,
anhydrous sodium tetraborate (also known as anhydrous borax) and
anhydrous boric acid.
[0063] Whichever degradable material is used in the present
invention, the degradable material may have any shape, including,
but not limited to, particles having the physical shape of
platelets, shavings, flakes, ribbons, rods, strips, spheroids,
toroids, pellets, tablets, or any other physical shape. In certain
embodiments of the present invention, the degradable material used
may comprise a mixture of fibers and spherical particles. One of
ordinary skill in the art, with the benefit of this disclosure,
will recognize the specific degradable material that may be used in
accordance with the present invention, and the preferred size and
shape for a given application.
[0064] In choosing the appropriate degradable material, one should
consider the degradation products that will result, and choose a
degradable material that will not yield degradation products that
would adversely affect other operations or components utilized in
that particular application. The choice of degradable material also
may depend, at least in part, on the conditions of the well (e.g.,
wellbore temperature). For instance, lactides have been found to be
suitable for lower temperature wells, including those within the
range of 60.degree. F. to 150.degree. F., and polylactides have
been found to be suitable for wellbore temperatures above this
range.
[0065] In some embodiments, a treatment fluid for use in the
present invention may further comprise an additive including, but
not limited to, fibers, salts, weighting agents, inert solids,
fluid loss control agents, emulsifiers, dispersion aids, corrosion
inhibitors, emulsion thinners, emulsion thickeners, viscosifying
agents, surfactants, particulates, lost circulation materials,
foaming agents, gases, pH control additives, breakers, biocides,
crosslinkers, stabilizers, chelating agents, scale inhibitors,
mutual solvents, oxidizers, reducers, friction reducers, clay
stabilizing agents, and any combination thereof.
[0066] By way of nonlimiting example, a treatment fluid may
comprise an aqueous base fluid, a tackifier, a proppant particle,
and a fiber. By way of another nonlimiting example, some
embodiments may involve sequentially introducing a first treatment
fluid and a second treatment fluid, wherein the first treatment
fluid may comprise an aqueous base fluid and a tackifier and the
second treatment fluid may comprise an aqueous base fluid, a
proppant particle, a fiber, and optionally a second tackifier.
[0067] Suitable fibers for use in conjunction with the present
invention may include, but are not limited to, natural organic
fibers, synthetic organic fibers, inorganic fibers, glass fibers,
carbon fibers, ceramic fibers, metal fibers, or any combination
thereof. Suitable fibers for use in conjunction with the present
invention may have an average length ranging from about 0.33 inches
to about 1 inch and have diameters ranging from about 10 microns to
about 1,000 microns. Further, fibers for use in conjunction with
the present invention may be bundles of about 5 to about 200
individual fibers.
[0068] To facilitate a better understanding of the present
invention, the following examples of preferred or representative
embodiments are given. In no way should the following examples be
read to limit, or to define, the scope of the invention.
EXAMPLES
Example 1
[0069] A treatment solution was prepared by diluting 5% v/v of
aqueous-based SANDWEDGE.RTM. ABC and fresh water containing 2% v/v
CLA-WEB.RTM. clay stabilizer.
[0070] A shale sample was immersed in a stirred beaker of the
treatment solution for 5 minutes, which simulates the exposure of
fracture faces to a treatment fluid comprising a tackifier as
described herein. The shale sample was removed and immersed in a
beaker of tap water containing 0.2% v/v CLA-WEB.RTM. clay
stabilizer and 5% w/v OK#1 sand (proppant). This suspension was
stirred enough to cause the proppant particles to circulate, which
stimulates the introduction of proppant particles into a tackifier
treated formation. The shale sample was removed for SEM
imaging.
[0071] FIGS. 2A-C provide SEM images parallel to the bedding planes
of the shale after exposure to the proppant particles.
Specifically, FIGS. 2A-C show, at increasing magnification
respectively, the adhesion of proppant particles to the surface of
the bedding planes. FIGS. 3A-C provide SEM images perpendicular to
the bedding planes of the shale after exposure to the proppant
particles. Specifically, FIGS. 3A-C show, at increasing
magnifications respectively, the adhesion of larger proppant
particles to the sides of the bedding planes without, in some
instances, support from a lower bedding plane. Further, some of the
smaller proppant particles are between bedding planes and appear to
be adhered, in some instances, to the upper bedding plane. These
figures demonstrate that the tackifier enables adhesion of the
proppant particles to subterranean fracture faces including between
the layers (i.e., bedding planes) of the formation, as best
illustrated in FIG. 3C.
[0072] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered, combined,
or modified and all such variations are considered within the scope
and spirit of the present invention. The invention illustratively
disclosed herein suitably may be practiced in the absence of any
element that is not specifically disclosed herein and/or any
optional element disclosed herein. While compositions and methods
are described in terms of "comprising," "containing," or
"including" various components or steps, the compositions and
methods can also "consist essentially of" or "consist of" the
various components and steps. All numbers and ranges disclosed
above may vary by some amount. Whenever a numerical range with a
lower limit and an upper limit is disclosed, any number and any
included range falling within the range is specifically disclosed.
In particular, every range of values (of the form, "from about a to
about b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be
understood to set forth every number and range encompassed within
the broader range of values. Also, the terms in the claims have
their plain, ordinary meaning unless otherwise explicitly and
clearly defined by the patentee. Moreover, the indefinite articles
"a" or "an," as used in the claims, are defined herein to mean one
or more than one of the element that it introduces. If there is any
conflict in the usages of a word or term in this specification and
one or more patent or other documents that may be incorporated
herein by reference, the definitions that are consistent with this
specification should be adopted.
* * * * *