U.S. patent application number 12/891889 was filed with the patent office on 2012-03-29 for diversion pill and methods of using the same.
Invention is credited to Yiyan Chen, Eric Clum.
Application Number | 20120073809 12/891889 |
Document ID | / |
Family ID | 45869453 |
Filed Date | 2012-03-29 |
United States Patent
Application |
20120073809 |
Kind Code |
A1 |
Clum; Eric ; et al. |
March 29, 2012 |
DIVERSION PILL AND METHODS OF USING THE SAME
Abstract
The invention provides a method made of steps of method
injecting into a wellbore, a composition comprising an aqueous
solution, a viscosifying agent, a degradable material, and sized
salt particulates; and allowing viscosity of the composition to
increase and form a plug at dynamic reservoir conditions.
Inventors: |
Clum; Eric; (Sugar Land,
TX) ; Chen; Yiyan; (Sugar Land, TX) |
Family ID: |
45869453 |
Appl. No.: |
12/891889 |
Filed: |
September 28, 2010 |
Current U.S.
Class: |
166/270 ;
166/305.1 |
Current CPC
Class: |
C09K 8/90 20130101; C09K
2208/08 20130101; C09K 2208/30 20130101; C09K 8/882 20130101; C09K
8/887 20130101; C09K 8/602 20130101; E21B 43/16 20130101; C09K 8/68
20130101 |
Class at
Publication: |
166/270 ;
166/305.1 |
International
Class: |
E21B 43/22 20060101
E21B043/22; E21B 43/16 20060101 E21B043/16 |
Claims
1. A method comprising: a. injecting into a wellbore, a composition
comprising an aqueous solution, a viscosifying agent, a degradable
material, and sized salt particulates; and b. allowing viscosity of
the composition to increase and form a plug at dynamic reservoir
conditions.
2. The method of claim 1, wherein the aqueous solution is
brine.
3. The method of claim 1, wherein the viscosifying agent is a
viscoelastic surfactant.
4. The method of claim 3, wherein the viscoelastic surfactant is a
mixture of erucylamidopropyl betaine and copolymer of polyvinyl
acetate/polyvinyl alcohol.
5. The method of claim 1, wherein the degradable material is
degradable fiber.
6. The method of claim 5, wherein the degradable fiber is a PLA
fiber.
7. The method of claim 1, wherein the sized salt particulates are
sized sodium chloride particulates.
8. The method of claim 1, wherein the sized salt particulates are
present in an amount of about 5% to about 30% by weight of the
composition.
9. The method of claim 8, wherein the sized salt particulates are
present in an amount of about 10% to about 20% by weight of the
composition.
10. The method of claim 1, wherein the dynamic reservoir conditions
include a shear rate above about 1 s.sup.-1.
11. The method of claim 10, wherein the dynamic reservoir
conditions include a shear rate above about 10 s.sup.-1.
12. The method of claim 1, wherein the composition further
comprises a breaker.
13. A method of diverting a treatment fluid in a wellbore
comprising: a. injecting into the wellbore the treatment fluid to
treat a first zone; b. injecting into the wellbore, a composition
comprising an aqueous solution, a viscosifying agent, a degradable
material, and sized salt particulates; c. allowing viscosity of the
composition to increase and form a plug at dynamic reservoir
conditions; and d. diverting the treatment fluid from first zone to
a second zone with the plug.
14. The method of claim 13, wherein formation of the plug is done
during continuous injection of the treatment fluid.
15. The method of claim 13, wherein the treatment fluid is a
fracturing fluid.
16. The method of claim 13, wherein the aqueous solution is
brine.
17. The method of claim 16, wherein the brine is near
saturation.
18. The method of claim 16, wherein the brine is saturated.
19. The method of claim 13, wherein the viscosifying agent is a
viscoelastic surfactant.
20. The method of claim 19, wherein the viscoelastic surfactant is
a mixture of erucylamidopropyl betaine and copolymer of polyvinyl
acetate/polyvinyl alcohol.
21. The method of claim 13, wherein the degradable material is
degradable fiber.
22. The method of claim 21, wherein the degradable fiber is a PLA
fiber.
23. The method of claim 13, wherein the sized salt particulates are
sized sodium chloride particulates.
24. The method of claim 13, wherein the sized salt particulates are
present in an amount of about 5% to about 30% by weight of the
composition.
25. The method of claim 24, wherein the sized salt particulates are
present in an amount of about 10% to about 20% by weight of the
composition.
26. The method of claim 13, wherein the dynamic reservoir
conditions include a shear rate above about 1 s.sup.-1.
27. The method of claim 26, wherein the dynamic reservoir
conditions include a shear rate above about 10 s.sup.-1.
28. A method of fracturing a subterranean formation in a wellbore
comprising: a. injecting into the wellbore a fracturing fluid to
create a fracture in the subterranean formation; b. injecting into
the wellbore, a composition comprising an aqueous solution, a
viscosifying agent, a degradable material, and sized salt
particulates; c. allowing viscosity of the composition to increase
and form a plug at dynamic reservoir conditions; and d. diverting
the fracturing fluid with the plug to create a second fracture in
the subterranean formation.
Description
FIELD OF THE INVENTION
[0001] The invention relates generally to the exploitation of
hydrocarbon-containing formations or injection wells. More
specifically, the invention relates to diverting agent and methods
of diverting in subterranean formations.
BACKGROUND
[0002] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0003] Hydrocarbons (oil, condensate, and gas) are typically
produced from wells that are drilled into the formations containing
them. For a variety of reasons, such as inherently low permeability
of the reservoirs or damage to the formation caused by drilling and
completion of the well, the flow of hydrocarbons into the well is
undesirably low. In this case, the well is "stimulated," for
example using hydraulic fracturing, chemical (usually acid)
stimulation, or a combination of the two (called acid fracturing or
fracture acidizing).
[0004] Hydraulic fracturing involves injecting fluids into a
formation at high pressures and rates such that the reservoir rock
fails and forms a fracture (or fracture network). Proppants are
typically injected in fracturing fluids after the pad to hold the
fracture(s) open after the pressures are released. In chemical
(acid) stimulation treatments, flow capacity is improved by
dissolving materials in the formation.
[0005] In hydraulic and acid fracturing, a first, viscous fluid
called a "pad" is typically injected into the formation to initiate
and propagate the fracture. This is followed by a second fluid that
contains a proppant to keep the fracture open after the pumping
pressure is released. Granular proppant materials may include sand,
ceramic beads, or other materials. In "acid" fracturing, the second
fluid contains an acid or other chemical such as a chelating agent
that can dissolve part of the rock, causing irregular etching of
the fracture face and removal of some of the mineral matter,
resulting in the fracture not completely closing when the pumping
is stopped. Occasionally, hydraulic fracturing is done without a
highly viscosified fluid (i.e., slick water) to minimize the damage
caused by polymers or the cost of other viscosifiers.
[0006] When multiple hydrocarbon-bearing zones are stimulated by
hydraulic fracturing or chemical stimulation, it is desirable to
treat the multiple zones in multiple stages. In multiple zone
fracturing, a first pay zone is fractured. Then, the fracturing
fluid is diverted to the next stage to fracture the next pay zone.
The process is repeated until all pay zones are fractured.
Alternatively, several pay zones may be fractured at one time, if
they are closely located with similar properties. Diversion may be
achieved with various techniques including formation of a temporary
plug using polymer gels or solid fluid loss materials.
[0007] Polymer gels have been widely used for conformance control
of naturally fissured/fractured reservoirs. For an overview of
existing polymer compositions, reference is made to the U.S. Pat.
Nos. 5,486,312 and 5,203,834 which also list a number of patents
and other sources related to gel-forming polymers.
[0008] Solid fluid loss materials can be used to plug up and
isolate the zone that has been previously stimulated or intended to
be omitted from treatment and divert treating fluids to the next
zones. Once stimulated; however, these plugged zones will need to
be accessible for production after the treatment is completed and
hence will require dissolution and removal of the plug.
[0009] The applicants found a method of using sized sodium chloride
salt as fluid loss additive/diverter, which is readily removed by
dissolving in water either from the excess water available from the
stimulation fluids returned during flowback of the stimulation
treatment or from produced water. The fluid used in placing this
diversion pill is solids-free VES fluid gelled in heavy brine which
carries the sodium chloride salt particulate and ensures cleanup
after the treatment.
SUMMARY
[0010] In a first aspect, a method is disclosed. The method
comprises injecting into a wellbore, a composition comprising an
aqueous solution, a viscosifying agent, a degradable material, and
sized salt particulates; and allowing viscosity of the composition
to increase and form a plug at dynamic reservoir conditions. By
dynamic reservoir conditions it is hereby meant with shear such as
for instance of above about 1 s.sup.-1, or above about 10
s.sup.-1.
[0011] In a second aspect, a method of diverting a treatment fluid
in a wellbore is disclosed. The method comprises injecting into the
wellbore the treatment fluid to treat a first zone; injecting into
the wellbore, a composition comprising an aqueous solution, a
viscosifying agent, a degradable material, and sized salt
particulates; allowing viscosity of the composition to increase and
form a plug at dynamic reservoir conditions; and diverting the
treatment fluid from first zone to a second zone with the plug.
[0012] In a third aspect, a method of fracturing a subterranean
formation in a wellbore is disclosed. The method comprises
injecting into the wellbore a fracturing fluid to create a fracture
in the subterranean formation; injecting into the wellbore, a
composition comprising an aqueous solution, a viscosifying agent, a
degradable material, and sized salt particulates; allowing
viscosity of the composition to increase and form a plug at dynamic
reservoir conditions; and diverting the fracturing fluid with the
plug to create a second fracture in the subterranean formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] FIG. 1 is a graph showing solubility versus temperature for
sodium chloride and potassium chloride.
[0014] FIG. 2 is a graph comparing viscosity (at 100/s) versus
temperature for samples 1 and 2.
[0015] FIG. 3 is a graph showing shear sweep (increasing shear
rate) at room temperature of sample from a relaxed state (first
run) followed by a shear activated state (second run) using fluid
Sample 3.
[0016] FIG. 4 is a graph showing viscosity measurement at 100/s at
room temperature for a relaxed sample 3.
[0017] FIG. 5 is a graph showing viscosity relaxing progress at
various shear rates at room temperature for sample 3 after sheared
at 500/s for 2 minutes.
DETAILED DESCRIPTION
[0018] At the outset, it should be noted that in the development of
any actual embodiments, numerous implementation-specific decisions
must be made to achieve the developer's specific goals, such as
compliance with system and business related constraints, which can
vary from one implementation to another. Moreover, it will be
appreciated that such a development effort might be complex and
time consuming but would nevertheless be a routine undertaking for
those of ordinary skill in the art having the benefit of this
disclosure.
[0019] The description and examples are presented solely for the
purpose of illustrating embodiments of the invention and should not
be construed as a limitation to the scope and applicability of the
invention. In the summary of the invention and this detailed
description, each numerical value should be read once as modified
by the term "about" (unless already expressly so modified), and
then read again as not so modified unless otherwise indicated in
context. Also, in the summary of the invention and this detailed
description, it should be understood that a concentration range
listed or described as being useful, suitable, or the like, is
intended that any and every concentration within the range,
including the end points, is to be considered as having been
stated. For example, "a range of from 1 to 10" is to be read as
indicating each and every possible number along the continuum
between about 1 and about 10. Thus, even if specific data points
within the range, or even no data points within the range, are
explicitly identified or refer to only a few specific, it is to be
understood that inventors appreciate and understand that any and
all data points within the range are to be considered to have been
specified, and that inventors possession of the entire range and
all points within the range disclosed and enabled the entire range
and all points within the range.
[0020] The following definitions are provided in order to aid those
skilled in the art in understanding the detailed description of the
invention.
[0021] The term "fracturing" refers to the process and methods of
breaking down a geological formation and creating a fracture, i.e.
the rock formation around a well bore, by pumping fluid at very
high pressures, in order to increase production rates from a
hydrocarbon reservoir. The fracturing methods otherwise use
conventional techniques known in the art.
[0022] The term "surfactant" refers to a soluble or partially
soluble compound that reduces the surface tension of liquids, or
reduces inter-facial tension between two liquids, or a liquid and a
solid by congregating and orienting itself at these interfaces.
[0023] The term "viscoelastic" refers to those viscous fluids
having elastic properties, i.e., the liquid at least partially
returns to its original form when an applied stress is
released.
[0024] The phrase "viscoelastic surfactant" or "VES" refers to that
class of compounds which can form micelles (spherulitic,
anisometric, lamellar, or liquid crystal) in the presence of
counter ions in aqueous solutions, thereby imparting viscosity to
the fluid. Anisometric micelles can be used, as their behavior in
solution most closely resembles that of a polymer.
[0025] According to a first embodiment, the composition is made
from: an aqueous solution, a viscosifying agent, a degradable
material, and sized salt particulates.
[0026] The aqueous solution may be fresh water or an aqueous
solution comprising mono, di or trivalent metal salts, ammonium or
mixtures of these. The salt can be present naturally if brine is
used, or can be added to the aqueous solution. For example, it is
possible to add to water; any salt, such as an alkali metal or
alkali earth metal salt (NaCO.sub.3, NaCl, KCl, etc.). In one
embodiment, the salt is generally present in weight percent
concentration between about 0.1% to about 5%, from about 1% to
about 3% by weight. One useful concentration is about 2% by weight.
In a second embodiment, the salt is at saturation conditions of the
respective brine. Effectively, if the aqueous solution is below
saturation then the sized salt particulates may begin dissolving.
For some applications, in particular where freezing might be
expected, the aqueous solution may further comprises an alcohol
such as methanol, ethanol, propanol or a polyalcohol such a glycol
or polyglycols or mixture thereof.
[0027] The viscosifying agent may be any crosslinked polymers. The
polymer viscosifier can be a metal-crosslinked polymer. Suitable
polymers for making the metal-crosslinked polymer viscosifiers
include, for example, polysaccharides such as substituted
galactomannans, such as guar gums, high-molecular weight
polysaccharides composed of mannose and galactose sugars, or guar
derivatives such as hydroxypropyl guar (HPG),
carboxymethylhydroxypropyl guar (CMHPG) and carboxymethyl guar
(CMG), hydrophobically modified guars, guar-containing compounds,
and synthetic polymers. Crosslinking agents based on boron,
titanium, zirconium or aluminum complexes are typically used to
increase the effective molecular weight of the polymer and make
them better suited for use in high-temperature wells.
[0028] Other suitable classes of polymers effective as viscosifying
agent include polyvinyl polymers, polymethacrylamides, cellulose
ethers, lignosulfonates, and ammonium, alkali metal, and alkaline
earth salts thereof. More specific examples of other typical water
soluble polymers are acrylic acid-acrylamide copolymers, acrylic
acid-methacrylamide copolymers, polyacrylamides, partially
hydrolyzed polyacrylamides, partially hydrolyzed
polymethacrylamides, polyvinyl alcohol, polyalkyleneoxides, other
galactomannans, heteropolysaccharides obtained by the fermentation
of starch-derived sugar and ammonium and alkali metal salts
thereof.
[0029] Cellulose derivatives are used to a smaller extent, such as
hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC),
carboxymethylhydroxyethylcellulose (CMHEC) and
carboxymethycellulose (CMC), with or without crosslinkers. Xanthan,
diutan, and scleroglucan, three biopolymers, have been shown to
have excellent particulate-suspension ability even though they are
more expensive than guar derivatives and therefore have been used
less frequently, unless they can be used at lower
concentrations.
[0030] In other embodiments, the viscosifying agent is made from a
crosslinkable, hydratable polymer and a delayed crosslinking agent,
wherein the crosslinking agent comprises a complex comprising a
metal and a first ligand selected from the group consisting of
amino acids, phosphono acids, and salts or derivatives thereof.
Also the crosslinked polymer can be made from a polymer comprising
pendant ionic moieties, a surfactant comprising oppositely charged
moieties, a clay stabilizer, a borate source, and a metal
crosslinker. Said embodiments are described in U.S. Patent
Publications US2008-0280790 and US2008-0280788 respectively, each
of which are incorporated herein by reference.
[0031] In other embodiments, the viscosifying agent may be a linear
(not cross-linked) polymer system.
[0032] The viscosifying agent may be a viscoelastic surfactant. The
viscoelastic surfactant is present in a low weight percent
concentration. Some suitable concentrations of viscoelastic
surfactant are about 0.001% to about 1.5% by weight, from about
0.01% to about 0.75% by weight, or even about 0.25%, about 0.5% or
about 0.75% by weight. However, it should be noted the effect of
increasing VES concentration is not limited to 1.5% by weight. The
increase in viscosity due to the addition of VES appears to
increase in an approximately linear manner with increasing
concentration of VES up to 1.5%, the highest concentration tested.
While economically it makes less sense to include higher VES
concentrations it is reasonable to presume that the same linear
increase in viscosity will occur with higher concentrations of
VES.
[0033] The VES may be selected from the group consisting of
cationic, anionic, zwitterionic, amphoteric, nonionic and
combinations thereof. Some non-limiting examples are those cited in
U.S. Pat. Nos. 6,435,277 (Qu et al.) and 6,703,352 (Dahayanake et
al.), each of which are incorporated herein by reference. The
viscoelastic surfactants, when used alone or in combination, are
capable of forming micelles that form a structure in an aqueous
environment that contribute to the increased viscosity of the fluid
(also referred to as "viscosifying micelles"). These fluids are
normally prepared by mixing in appropriate amounts of VES suitable
to achieve the desired viscosity. The viscosity of VES fluids may
be attributed to the three dimensional structure formed by the
components in the fluids. When the concentration of surfactants in
a viscoelastic fluid significantly exceeds a critical
concentration, and in most cases in the presence of an electrolyte,
surfactant molecules aggregate into species such as micelles, which
can interact to form a network exhibiting viscous and elastic
behavior.
[0034] In general, particularly suitable zwitterionic surfactants
have the formula:
RCONH--(CH.sub.2).sub.a(CH.sub.2CH.sub.2O).sub.m(CH.sub.2).sub.b--N.sup.-
+(CH.sub.3).sub.2--(CH.sub.2).sub.a'(CH.sub.2CH.sub.2O).sub.m'(CH.sub.2).s-
ub.b'COO.sup.-
in which R is an alkyl group that contains from about 11 to about
23 carbon atoms which may be branched or straight chained and which
may be saturated or unsaturated; a, b, a', and b' are each from 0
to 10 and m and m' are each from 0 to 13; a and b are each 1 or 2
if m is not 0 and (a+b) is from 2 to 10 if m is 0; a' and b' are
each 1 or 2 when m' is not 0 and (a'+b') is from 1 to 5 if m is 0;
(m+m') is from 0 to 14; and CH.sub.2CH.sub.2O may also be
OCH.sub.2CH.sub.2.
[0035] In some embodiments, a zwitterionic surfactants of the
family of betaine is used. Two suitable examples of betaines are
BET-O and BET-E. The surfactant in BET-O-30 is shown below; one
chemical name is oleylamidopropyl betaine. It is designated
BET-O-30 because as obtained from the supplier (Rhodia, Inc.
Cranbury, N.J., U.S. A.) it is called Mirataine BET-O-30 because it
contains an oleyl acid amide group (including a C.sub.17H.sub.33
alkene tail group) and contains about 30% active surfactant; the
remainder is substantially water, sodium chloride, and propylene
glycol. An analogous material, BET-E-40, is also available from
Rhodia and contains an erucic acid amide group (including a
C.sub.21H.sub.41 alkene tail group) and is approximately 40% active
ingredient, with the remainder being substantially water, sodium
chloride, and isopropanol. VES systems, in particular BET-E-40,
optionally contain about 1% of a condensation product of a
naphthalene sulfonic acid, for example sodium polynaphthalene
sulfonate, as a rheology modifier, as described in U.S. Patent
Application Publication No. 2003-0134751. The surfactant in
BET-E-40 is also shown below; one chemical name is
erucylamidopropyl betaine. BET surfactants, and other VES's that
are suitable for the embodiments are described in U.S. Pat. No.
6,258,859. According to that patent, BET surfactants make
viscoelastic gels when in the presence of certain organic acids,
organic acid salts, or inorganic salts; in that patent, the
inorganic salts were present at a weight concentration up to about
30%. Co-surfactants may be useful in extending the brine tolerance,
and to increase the gel strength and to reduce the shear
sensitivity of the VES-fluid, in particular for BET-O-type
surfactants. An example given in U.S. Pat. No. 6,258,859 is sodium
dodecylbenzene sulfonate (SDBS), also shown below. Other suitable
co-surfactants include, for example those having the SDBS-like
structure in which x=5-15; other co-surfactants are those in which
x=7-15. Still other suitable co-surfactants for BET-O-30 are
certain chelating agents such as trisodium
hydroxyethylethylenediamine triacetate. The composition may be used
with viscoelastic surfactant fluid systems that contain such
additives as co-surfactants, organic acids, organic acid salts,
and/or inorganic salts.
##STR00001## [0036] Surfactant in BET-O-30 (when n=3 and p=1)
[0036] ##STR00002## [0037] Surfactant in BET-E-40 (when n=3 and
p=1)
[0037] ##STR00003## [0038] SDBS (when x=11 and the counter-ion is
Na.sup.+)
[0039] Some embodiments use betaines; for example BET-E-40.
Although experiments have not been performed, it is believed that
mixtures of betaines, especially BET-E-40, with other surfactants
are also suitable.
[0040] Other betaines that are suitable include those in which the
alkene side chain (tail group) contains 17-23 carbon atoms (not
counting the carbonyl carbon atom) which may be branched or
straight chained and which may be saturated or unsaturated, n=2-10,
and p=1-5, and mixtures of these compounds. Some betaines are those
in which the alkene side chain contains 17-21 carbon atoms (not
counting the carbonyl carbon atom) which may be branched or
straight chained and which may be saturated or unsaturated, n=3-5,
and p=1-3, and mixtures of these compounds. These surfactants are
used at a concentration of about 0.5 to about 10%, or from about 1
to about 5%, or even from about 1.5 to about 4.5%.
[0041] Exemplary cationic viscoelastic surfactants include the
amine salts and quaternary amine salts disclosed in U.S. Pat. Nos.
5,979,557, and 6,435,277 which are hereby incorporated by
reference. Examples of suitable cationic viscoelastic surfactants
include cationic surfactants having the structure:
R.sub.1N.sup.+(R.sub.2)(R.sub.3)(R.sub.4)X.sup.-
in which R.sub.1 has from about 14 to about 26 carbon atoms and may
be branched or straight chained, aromatic, saturated or
unsaturated, and may contain a carbonyl, an amide, a retroamide, an
imide, a urea, or an amine; R.sub.2, R.sub.3, and R.sub.4 are each
independently hydrogen or a C.sub.1 to about C.sub.6 aliphatic
group which may be the same or different, branched or straight
chained, saturated or unsaturated and one or more than one of which
may be substituted with a group that renders the R.sub.2, R.sub.3,
and R.sub.4 group more hydrophilic; the R.sub.2, R.sub.3 and
R.sub.4 groups may be incorporated into a heterocyclic 5- or
6-member ring structure which includes the nitrogen atom; the
R.sub.2, R.sub.3 and R.sub.4 groups may be the same or different;
R.sub.1, R.sub.2, R.sub.3 and/or R.sub.4 may contain one or more
ethylene oxide and/or propylene oxide units; and X.sup.- is an
anion. Mixtures of such compounds are also suitable. As a further
example, R.sub.1 is from about 18 to about 22 carbon atoms and may
contain a carbonyl, an amide, or an amine, and R.sub.2, R.sub.3,
and R.sub.4 are the same as one another and contain from 1 to about
3 carbon atoms.
[0042] Cationic surfactants having the structure
R.sub.1N.sup.+(R.sub.2)(R.sub.3)(R.sub.4)X.sup.- may optionally
contain amines having the structure RiN(R.sub.2)(R.sub.3). It is
well known that commercially available cationic quaternary amine
surfactants often contain the corresponding amines (in which
R.sub.1, R.sub.2, and R.sub.3 in the cationic surfactant and in the
amine have the same structure). As received commercially available
VES surfactant concentrate formulations, for example cationic VES
surfactant formulations, may also optionally contain one or more
members of the group consisting of alcohols, glycols, organic
salts, chelating agents, solvents, mutual solvents, organic acids,
organic acid salts, inorganic salts, oligomers, polymers,
co-polymers, and mixtures of these members. They may also contain
performance enhancers, such as viscosity enhancers, for example
polysulfonates, for example polysulfonic acids, as described in
U.S. Pat. No. 7,084,095 which is hereby incorporated by
reference.
[0043] Another suitable cationic VES is erucyl
bis(2-hydroxyethyl)methyl ammonium chloride, also known as (Z)-13
docosenyl-N--N-bis(2-hydroxyethyl)methyl ammonium chloride. It is
commonly obtained from manufacturers as a mixture containing about
60 weight percent surfactant in a mixture of isopropanol, ethylene
glycol, and water. Other suitable amine salts and quaternary amine
salts include (either alone or in combination in accordance with
the invention), erucyl trimethyl ammonium chloride;
N-methyl-N,N-bis(2-hydroxyethyl) rapeseed ammonium chloride; oleyl
methyl bis(hydroxyethyl) ammonium chloride;
erucylamidopropyltrimethylamine chloride, octadecyl methyl
bis(hydroxyethyl)ammonium bromide; octadecyl
tris(hydroxyethyl)ammonium bromide; octadecyl dimethyl hydroxyethyl
ammonium bromide; cetyl dimethyl hydroxyethyl ammonium bromide;
cetyl methyl bis(hydroxyethyl)ammonium salicylate; cetyl methyl
bis(hydroxyethyl)ammonium 3,4,-dichlorobenzoate; cetyl
tris(hydroxyethyl)ammonium iodide; cosyl dimethyl hydroxyethyl
ammonium bromide; cosyl methyl bis(hydroxyethyl)ammonium chloride;
cosyl tris(hydroxyethyl)ammonium bromide; dicosyl dimethyl
hydroxyethyl ammonium bromide; dicosyl methyl
bis(hydroxyethyl)ammonium chloride; dicosyl
tris(hydroxyethyl)ammonium bromide; hexadecyl ethyl
bis(hydroxyethyl)ammonium chloride; hexadecyl isopropyl
bis(hydroxyethyl)ammonium iodide; and cetylamino, N-octadecyl
pyridinium chloride.
[0044] Amphoteric viscoelastic surfactants are also suitable.
Exemplary amphoteric viscoelastic surfactant systems include those
described in U.S. Pat. No. 6,703,352, for example amine oxides.
Other exemplary viscoelastic surfactant systems include those
described in U.S. Pat. Nos. 6,239,183; 6,506,710; 7,060,661;
7,303,018; and 7,510,009 for example amidoamine oxides. These
references are hereby incorporated in their entirety. Mixtures of
zwitterionic surfactants and amphoteric surfactants are suitable.
An example is a mixture of about 13% isopropanol, about 5%
1-butanol, about 15% ethylene glycol monobutyl ether, about 4%
sodium chloride, about 30% water, about 30% cocoamidopropyl
betaine, and about 2% cocoamidopropylamine oxide.
[0045] The viscoelastic surfactant system may also be based upon
any suitable anionic surfactant. In some embodiments, the anionic
surfactant is an alkyl sarcosinate. The alkyl sarcosinate can
generally have any number of carbon atoms. Alkyl sarcosinates can
have about 12 to about 24 carbon atoms. The alkyl sarcosinate can
have about 14 to about 18 carbon atoms. Specific examples of the
number of carbon atoms include 12, 14, 16, 18, 20, 22, and 24
carbon atoms. The anionic surfactant is represented by the chemical
formula:
R.sub.1CON(R.sub.2)CH.sub.2X
wherein R.sub.1 is a hydrophobic chain having about 12 to about 24
carbon atoms, R.sub.2 is hydrogen, methyl, ethyl, propyl, or butyl,
and X is carboxyl or sulfonyl. The hydrophobic chain can be an
alkyl group, an alkenyl group, an alkylarylalkyl group, or an
alkoxyalkyl group. Specific examples of the hydrophobic chain
include a tetradecyl group, a hexadecyl group, an octadecentyl
group, an octadecyl group, and a docosenoic group.
[0046] To provide the ionic strength for the desired micelle
formation, in some cases, the composition may comprise
water-soluble salts. Adding salt may help promote micelle formation
for the viscosification of the fluid in some instances. Suitable
water-soluble salts may comprise lithium, ammonium, sodium,
potassium, cesium, magnesium, calcium, or zinc cations, and
chloride, bromide, iodide, formate, nitrate, acetate, cyanate, or
thiocyanate anions. Examples of suitable water-soluble salts that
comprise the above-listed anions and cations include, but are not
limited to, ammonium chloride, lithium bromide, lithium chloride,
lithium formate, lithium nitrate, calcium bromide, calcium
chloride, calcium nitrate, calcium formate, sodium bromide, sodium
chloride, sodium formate, sodium nitrate, potassium chloride,
potassium bromide, potassium nitrate, potassium formate, cesium
nitrate, cesium formate, cesium chloride, cesium bromide, magnesium
chloride, magnesium bromide, zinc chloride, and zinc bromide.
[0047] The degradable material may be degradable fibers, granular
materials, particulates, flakes or particles made of degradable
polymers. The differing molecular structures of the degradable
materials that are suitable give a wide range of possibilities
regarding regulating the degradation rate of the degradable
material. In choosing the appropriate degradable material, one
should consider the degradation products that will result. For
instance, some may form an acid upon degradation, and the presence
of the acid may be undesirable; others may form degradation
products that would be insoluble, and these may be undesirable.
Moreover, these degradation products should not adversely affect
other operations or components.
[0048] The degradability of a polymer depends at least in part on
its backbone structure. One of the more common structural
characteristics is the presence of hydrolyzable and/or oxidizable
linkages in the backbone. The rates of degradation of, for example,
polyesters, are dependent on the type of repeat unit, composition,
sequence, length, molecular geometry, molecular weight, morphology
(e.g., crystallinity, size of spherulites, and orientation),
hydrophilicity, surface area, and additives. Also, the environment
to which the polymer is subjected may affect how the polymer
degrades, e.g., temperature, presence of moisture, oxygen,
microorganisms, enzymes, pH, and the like. One of ordinary skill in
the art, with the benefit of this disclosure, will be able to
determine what the optimum polymer would be for a given application
considering the characteristics of the polymer utilized and the
environment to which it will be subjected.
[0049] Suitable examples of polymers that may be used include, but
are not limited to, homopolymers, random aliphatic polyester
copolymers, block aliphatic polyester copolymers, star aliphatic
polyester copolymers, or hyperbranched aliphatic polyester
copolymers. Such suitable polymers may be prepared by
polycondensation reactions, ring-opening polymerizations, free
radical polymerizations, anionic polymerizations, carbocationic
polymerizations, coordinative ring-opening polymerization for, such
as, lactones, and any other suitable process. Specific examples of
suitable polymers include polysaccharides such as dextran or
cellulose; chitins; chitosans; proteins; aliphatic polyesters;
poly(lactides); poly(glycolides); poly(8-caprolactones);
poly(hydroxy ester ethers); poly(hydroxybutyrates); polyanhydrides;
polycarbonates; poly(orthoesters); poly(acetals); poly(acrylates);
poly(alkylacrylates); poly(amino acids); poly(ethylene oxide); poly
ether esters; polyester amides; polyamides; polyphosphazenes; and
copolymers or blends thereof. Other degradable polymers that are
subject to hydrolytic degradation also may be suitable. One
guideline for choosing which composite particles to use in a
particular application is what degradation products will result.
Another guideline is the conditions surrounding a particular
application.
[0050] Of these suitable polymers, aliphatic polyesters are
preferred. Of the suitable aliphatic polyesters, polyesters of
.alpha. or .beta. hydroxy acids are preferred. Poly(lactide) is
most preferred. Poly(lactide) is synthesized either from lactic
acid by a condensation reaction or more commonly by ring-opening
polymerization of cyclic lactide monomer. The lactide monomer
exists generally in three different forms: two stereoisomers L- and
D-lactide; and D,L-lactide (meso-lactide). The chirality of the
lactide units provides a means to adjust, inter alia, degradation
rates, as well as the physical and mechanical properties after the
lactide is polymerized. Poly(L-lactide), for instance, is a
semicrystalline polymer with a relatively slow hydrolysis rate.
This could be desirable in applications where slow degradation of
the degradable material is desired. Poly(D,L-lactide) is an
amorphous polymer with a much faster hydrolysis rate. The
stereoisomers of lactic acid may be used individually or combined
for use in the compositions and methods of the present embodiments.
Additionally, they may be copolymerized with, for example,
glycolide or other monomers like .epsilon.-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 aliphatic polyesters. For
example, the degradation rate of polylactic acid may be affected by
blending, for example, high and low molecular weight polylactides;
mixtures of polylactide and lactide monomer; or by blending
polylactide with other aliphatic polyesters.
[0051] The physical properties of degradable polymers may depend on
several factors such as the composition of the repeat units,
flexibility of the chain, presence of polar groups, molecular mass,
degree of branching, crystallinity, orientation, etc. For example,
short chain branches reduce the degree of crystallinity of polymers
while long chain branches lower the melt viscosity and impart,
inter alia, extensional viscosity with tension-stiffening behavior.
The properties of the material utilized can be further 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, etc.). The properties of any
such suitable degradable polymers (such as hydrophilicity, rate of
biodegration, etc.) can be tailored by introducing functional
groups along the polymer chains. 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 effect.
[0052] In an embodiment, the degradable material degrades after
temporarily sealing during the treatment operation, and helps
restore permeability and conductivity for reservoir fluid
production. The delayed degradation of polyester generally includes
hydrolysis of the ester moieties at downhole conditions of elevated
temperature and an aqueous environment into hydrolysis such as
carboxylic acid and hydroxyl moieties, for example. The hydrolysis
in one embodiment can render the degradable material degradation
products entirely soluble in the downhole and/or reservoir fluids.
In an alternative or additional embodiment, the entire degradable
material need not be entirely soluble following polyester
degradation; it is sufficient only that enough hydrolysis occurs so
as to allow the residue of the degraded or partially degraded
degradable material to be lifted off of the sealed surface by a low
backflow pressure from produced reservoir fluids.
[0053] In some embodiments, the degradable materials are in the
form of beads, powder, spheres, ribbons, platelets, fibers, flakes,
or any other shape with an aspect ratio equal to or greater than
one. In some embodiments, the degradable materials include
particles having an aspect ratio greater than 10, greater than 100,
greater than 200, greater than 250 or the like, such as platelets
or fibers or the like. The blended materials can take any form of
composites, for example biodegradable material coatings or
scaffolds with other materials dispersed therein. Further, the
degradable particles can be nano-, micro-, or mesoporous structures
that are fractal or non-fractal.
[0054] The sized salt particulates or graded salt particulates may
comprise lithium, ammonium, sodium, potassium, cesium, magnesium,
calcium, or zinc cations, and chloride, bromide, iodide, formate,
nitrate, acetate, cyanate, or thiocyanate anions. Examples of
suitable sized salt particulates that comprise the above-listed
anions and cations include, but are not limited to, ammonium
chloride, lithium bromide, lithium chloride, lithium formate,
lithium nitrate, calcium bromide, calcium chloride, calcium
nitrate, calcium formate, sodium bromide, sodium chloride, sodium
formate, sodium nitrate, potassium chloride, potassium bromide,
potassium nitrate, potassium formate, cesium nitrate, cesium
formate, cesium chloride, cesium bromide, magnesium chloride,
magnesium bromide, zinc chloride, and zinc bromide.
[0055] In one embodiment, the sized salt particulates are sized
sodium chloride. Sodium chloride salt can easily be dissolved by
water or unsaturated brines; using it as fluid loss/diverter solid
makes it ideal for post treatment cleanup. When sodium chloride
particles are used, the aqueous solution is preferably a brine near
saturation condition or even at saturation condition. Effectively,
the sodium chloride particles may begin dissolving in the aqueous
solution and may not function as an effective diverter, if the
brine is not near saturation condition. NaCl has a close to
constant solubility in water with respect to temperature changes;
therefore, is perfect to be used to formulate a diversion or fluid
loss pill at different temperatures. Different brines can be
selected to formulate this diversion pill with the solid NaCl
salt.
[0056] NaCl is chosen as the solid salt fluid loss
additive/diverter due to its relatively flat solubility curve with
respect to the solution temperature. As shown in FIG. 1, NaCl
solubility in both fresh water and 11.6 ppg CaCl.sub.2 exhibits
nominal change across a wide temperature range, while KCl on the
other hand, solubility increases significantly with increases in
temperature. This makes NaCl a preferred diverting particulate
since it remains in a solid state in a saturated NaCl brine or
CaCl.sub.2 carrying medium while being pumped and placed.
[0057] According to a further embodiment, the composition may
further comprise additives as surfactants, dispersants, breakers,
anti-oxidants, corrosion inhibitors, delay agents, biocides,
buffers, fluid loss additives, pH control agents, solid acids,
solid acid precursors, organic scale inhibitors, inorganic scale
inhibitors, demulsifying agents, paraffin inhibitors, corrosion
inhibitors, gas hydrate inhibitors, asphaltene treating chemicals,
foaming agents, fluid loss agents, water blocking agents, EOR
enhancing agents, or the like. The additive may also be a
biological agent.
[0058] The composition is compatible with other fluids or material
as for example hydrocarbons such as mineral oil (only if non-VES
fluids are used), proppants or additives normally found in well
stimulation. Current embodiments can be used in various
applications including temporary plugs formation, kill plugs, or
multiple fracturing steps for to treating subterranean formations
having a plurality of zones of differing permeabilities.
[0059] According to a first aspect, the method comprises injecting
into a wellbore, the composition and allowing viscosity of the
composition to increase and form a plug at dynamic reservoir
conditions. By dynamic reservoir conditions it is hereby meant with
shear such as for instance of above about 1 s.sup.-1, or above
about 10 s.sup.-1. The composition is a shear thickening fluid,
i.e. low viscosity at rest, but can be activated when enough
shearing energy is applied. This behavior is useful in the
diversion applications as it has low viscosity during pumping, but
is shear activated when flowed through the high perm zone, natural
fractures, or a previous fractured zone, where the flow rate there
is high and hence shear rate is high. This activated fluid will
have higher viscosity in blocking off or providing higher
resistance to this zone or to perforations. Once the fluid is no
longer sheared, it will gradually relax to low to no viscosity,
facilitating the cleanup in flowback.
[0060] Application could be used for fracture stimulation
treatments in new or refraced horizontal or vertical wells to
achieve near-wellbore diversion by opening entirely new zones to
the treatment or restimulation that effectively extends the former
stimulation within an older pre-existing fractured zone. The
combination of salt in a saturated or nonreactive brine along with
fiber in a brine compatible VES fluid are used as the diverter pill
that is placed to effect diversion. After the treatment the entire
diverter pill is degradable and can be flowed back to surface.
[0061] To facilitate a better understanding of some embodiments,
the following examples of embodiments are given. In no way should
the following examples be read to limit, or define, the scope of
the embodiments described herewith.
EXAMPLES
[0062] Series of experiments were conducted to demonstrate
properties of compositions and methods as disclosed above.
[0063] Two kinds of fluid examples will be shown here. One is with
CaCl.sub.2 brine, and the other is using saturated NaCl brine.
Shown in FIG. 2 are two viscosity (at 100 s.sup.-1) versus
temperature profiles for two different fluid samples. Both samples
used 11.6 ppg CaCl.sub.2 with no less than 20% solid NaCl added.
Sample 1 has 0.67% of active BET-E surfactant and 0.11% copolymer
of polyvinyl acetate/polyvinyl alcohol rheology modifier while
sample 2 has 1.5% of active BET-E surfactant and 0.25% copolymer of
polyvinyl acetate/polyvinyl alcohol rheology modifier. As can be
seen from the figure, both fluid viscosities are maintained as
temperatures are raised. In addition, as shown in table 1, the n'
of these two fluids are well below 1, indicating that the fluid is
a viscoelastic fluid. The addition of the NaCl in this system did
not impair the VES fluid performances.
TABLE-US-00001 TABLE 1 n' of sample 1 and 2 at various temperatures
Sample 1 Sample 2 TEMP (degF.) n' TEMP (degF.) n' 77 0.375 76 0.406
103 0.413 103 0.361 122 0.482 123 0.26 142 0.498 142 0.181 166
0.461 167 0.196 192 0.566 194 0.37 216 0.432 219 0.177 238 0.812
241 0.09 261 0.176 281 0.502
[0064] Another kind of fluid example is made with solid NaCl in a
saturated NaCl brine. The sample 3 fluid contains 0.67% of active
BET-E surfactant and 0.11% copolymer of polyvinyl acetate/polyvinyl
alcohol rheology modifier.
[0065] Sample 3 was prepared in Waring blender then allowed to sit
without disturbance in a relaxed state for a few minutes. The
sample was then loaded to the Bohlin rheometer and sheared from low
shear (0.1 s.sup.-1) to high shear (500 s.sup.-1) and then remained
at high shear for 2 minutes. The same sample was then run for the
same shear sweep again. As shown in FIG. 3, the second run after
the fluid is shear activated gives much higher viscosity at low
shear to about 10 s.sup.1. In fact, it can be seen from the first
run that the fluid follows a power law slope up to 10 s.sup.-1 and
then deviates from it indicating the fluid is shear thickening at
this shear rate.
[0066] To further confirm this shear activation property, a relaxed
sample 3 was sheared at 100 s.sup.-1 shear rate and the viscosity
profile was recorded (FIG. 4). The fluid viscosity for the first 2
minutes increased with time confirming that the fluid is being
shear activated.
[0067] The activated fluid decay (relax) in viscosity can also be
measured with the rheometer. Sample 3 was shear activated by
applying 500 s.sup.-1 shear for 2 minutes, then measured at 100, 10
and 1 s.sup.-1 respectively for 20 minutes. The results are plotted
in FIG. 5. For comparison, the viscosity decreases are normalized
with the initial viscosity at that shear rate immediately after 500
s.sup.-1 shear. At 100 s.sup.-1, the shear energy is still high
enough to keep the fluid at a shear activated state, so the
viscosity trace basically remains flat throughout the measurement
period. At 1 s.sup.-1, the fluid is close to not being sheared;
therefore, it relaxes rapidly in about 3 minutes. At 10 s.sup.1
shear rate, the behavior is inbetween the other two shear rates
since there is still some shear energy being put into the system
and the fluid can not fully relax, therefore, it takes longer (-7
minutes) to relax than at 1 s.sup.-1, and the final equilibrium
viscosity is higher (-15% of fully shear activated viscosity). This
behavior allows us to pick the right shear to tune the fluid
viscosities.
[0068] The particular embodiments disclosed above are illustrative
only, as the 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 herein shown, other than as described
in the claims below. It is therefore evident that the particular
embodiments disclosed above may be altered or modified and all such
variations are considered within the scope of the embodiments
described herewith. Accordingly, the protection sought herein is as
set forth in the claims below.
* * * * *