U.S. patent application number 13/629664 was filed with the patent office on 2014-04-03 for methods for treating wellbore and wellbore operation fluids.
The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Mary A. Hardy-McGowen, Paul D. Lord, Jimmie D. Weaver.
Application Number | 20140090833 13/629664 |
Document ID | / |
Family ID | 50384123 |
Filed Date | 2014-04-03 |
United States Patent
Application |
20140090833 |
Kind Code |
A1 |
Weaver; Jimmie D. ; et
al. |
April 3, 2014 |
Methods for Treating Wellbore and Wellbore Operation Fluids
Abstract
Method comprising providing a portion of a subterranean
formation having a first formation bacterial count as a result of
the presence of a plurality of bacteria in the formation; providing
a wellbore treatment fluid having a first wellbore treatment fluid
bacterial count as a result of the presence of a plurality of
bacteria in the wellbore treatment fluid; combining the wellbore
treatment fluid with a a plurality of bacteriocins; placing the
wellbore treatment fluid into a wellbore in the portion of the
subterranean formation; reducing the first formation bacterial
count to a second formation bacterial count; and reducing the first
wellbore treatment fluid bacterial count to a second wellbore
treatment fluid bacterial count.
Inventors: |
Weaver; Jimmie D.; (Duncan,
OK) ; Lord; Paul D.; (Houston, TX) ;
Hardy-McGowen; Mary A.; (Adelaide, AU) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Family ID: |
50384123 |
Appl. No.: |
13/629664 |
Filed: |
September 28, 2012 |
Current U.S.
Class: |
166/246 |
Current CPC
Class: |
E21B 37/06 20130101;
A01N 63/10 20200101; A01N 25/26 20130101; A01N 37/44 20130101; C09K
8/605 20130101; A01N 63/10 20200101; A01N 63/10 20200101; A01N
25/26 20130101; A01N 37/44 20130101; C09K 8/035 20130101 |
Class at
Publication: |
166/246 |
International
Class: |
E21B 37/06 20060101
E21B037/06 |
Claims
1. A method comprising: providing a portion of a subterranean
formation having a first formation bacterial count as a result of
the presence of a plurality of bacteria in the formation; providing
a wellbore treatment fluid having a first wellbore treatment fluid
bacterial count as a result of the presence of a plurality of
bacteria in the wellbore treatment fluid; combining the wellbore
treatment fluid with a a plurality of bacteriocins; placing the
wellbore treatment fluid into a wellbore in the portion of the
subterranean formation; reducing the first formation bacterial
count to a second formation bacterial count; and reducing the first
wellbore treatment fluid bacterial count to a second wellbore
treatment fluid bacterial count.
2. The method of claim 1, wherein the bacteriocins are
gram-positive bacteria produced bacteriocins, gram-negative
bacteria produced bacteriocins, or a combination thereof.
3. The method of claim 1, wherein the bacteriocins are
gram-positive bacteria produced bacteriocins selected from the
group consisting of: acidocin; actagardine; bovicin; brochocin;
butyrivibriocin; carnobacteriocin; carnocin; carnocyclin;
circularin; closticin; coagulin; curvacin; curvaticin; cytolysin;
divercin; divergicin; duramycin; enterocin; entianin; epicidin;
epidermin; epilancin; ericin; gallidermin; garvicin; gassericin;
haloduracin; hiracin; hominicin; ipomicin; lactacin; lactoccin;
lactocyclin; lantibiotic; leucocin; lichenicidin; listeriocin;
lysostaphin; mesentericin; microbisporicin; mundticin; mutacin;
nisin; paenibacillin; pediocin; pep5 lantibiotic; piscicolin;
plantaricin; sakacin; salivaricin; smb; staphylococcin; and any
combination thereof.
4. The method of claim 1, wherein the bacteriocins are
gram-negative bacteria produced bacteriocins selected from the
group consisting of: capistruin; colicin; microcin; pyrocin;
serracin; and any combination thereof.
5. The method of claim 1, wherein the wellbore treatment fluid
further comprises a chelating agent selected from the group
consisting of: EDTA; CaEDT; CaNa.sub.2EDTA; alkyldiamine
tetraacetate; EGTA; citrate; and any combination thereof.
6. The method of claim 5, wherein the chelating agent is present in
an amount from about 0.1 mM to about 30 mM of the wellbore
treatment fluid.
7. The method of claim 1, wherein the wellbore treatment fluid
further comprises an ionic surfactant selected from the group
consisting of: an emulsifier; a fatty acid; a quaternary compound;
an anionic surfactant; an amphoteric surfactant; and any
combination thereof.
8. The method of claim 1, wherein the wellbore treatment fluid
further comprises a nonionic surfactant selected from the group
consisting of: a polyoxyalkylphenol; a polyoxyalkysorbitan; a
glyceride; and any combination thereof.
9. A method comprising: providing a portion of a subterranean
formation; providing a flowback fluid that has previously been
present in a portion of a subterranean formation; wherein the
flowback fluid has a first bacterial count as a result of the
presence of a plurality of bacteria; combining the flowback fluid
with a plurality of bacteriocins; and reducing the first bacterial
count to a second bacterial count.
10. The method of claim 9, wherein the bacteriocins are
gram-positive bacteria produced bacteriocins, gram-negative
bacteria produced bacteriocins, or a combination thereof.
11. The method of claim 9, wherein the bacteriocins are
gram-positive bacteria produced bacteriocins selected from the
group consisting of: acidocin; actagardine; bovicin; brochocin;
butyrivibriocin; carnobacteriocin; carnocin; carnocyclin;
circularin; closticin; coagulin; curvacin; curvaticin; cytolysin;
divercin; divergicin; duramycin; enterocin; entianin; epicidin;
epidermin; epilancin; ericin; gallidermin; garvicin; gassericin;
haloduracin; hiracin; hominicin; ipomicin; lactacin; lactoccin;
lactocyclin; lantibiotic; leucocin; lichenicidin; listeriocin;
lysostaphin; mesentericin; microbisporicin; mundticin; mutacin;
nisin; paenibacillin; pediocin; pep5 lantibiotic; piscicolin;
plantaricin; sakacin; salivaricin; smb; staphylococcin; and any
combination thereof.
12. The method of claim 9, wherein the bacteriocins are
gram-negative bacteria produced bacteriocins selected from the
group consisting of: capistruin; colicin; microcin; pyrocin;
serracin; and any combination thereof.
13. The method of claim 9, wherein the flowback fluid further
comprises a chelating agent selected from the group consisting of:
EDTA; CaEDTA; CaNa.sub.2EDTA; alkyldiamine tetraacetate; EGTA;
citrate; and any combination thereof.
14. The method of claim 9, wherein the flowback fluid further
comprises an ionic surfactant selected from the group consisting
of: an emulsifier; a fatty acid; a quaternary compound; an anionic
surfactant; an amphoteric surfactant; and any combination
thereof.
15. The method of claim 9, wherein the flowback fluid further
comprises a nonionic surfactant selected from the group consisting
of: a polyoxyalkylphenol; a polyoxyalkysorbitan; a glyceride; and
any combination thereof.
16. A method comprising: providing a portion of a subterranean
formation having a first formation bacterial count as a result of
the presence of a plurality of bacteria in the formation; providing
a wellbore treatment fluid having a first wellbore treatment fluid
bacterial count as a result of the presence of a plurality of
bacteria in the wellbore treatment fluid; providing particulates
having a coating of bacteriocins thereon and a coating of
degradable material atop of the coating of bacteriocins; wherein
the degradable coating is a polysaccharide, a cellulose, a chitin,
a chitosan, a protein, an aliphatic polyester, a poly(lactide), a
poly(glycolide), a poly(.epsilon.-caprolactone), a
poly(hydrobutyrate), a poly(anhydride), an aliphatic polycarbonate,
a poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a
poly(vinylidene chloride), a polyphosphazene, or a combination
thereof combining the wellbore treatment fluid with a plurality of
bacteriocins; combining the wellbore treatment fluid with the
coated particulates; placing the wellbore treatment fluid
comprising the coated particulates into a portion of the
subterranean formation; releasing the bacteriocins as the
degradable coating degrades; reducing the first formation bacterial
count to a second formation bacterial count; and reducing the first
wellbore treatment fluid bacterial count to a second wellbore
treatment fluid bacterial count.
17. The method of claim 16, wherein the bacteriocins are
gram-positive bacteria produced bacteriocins, gram-negative
bacteria produced bacteriocins, or a combination thereof.
18. The method of claim 16, wherein the bacteriocins are
gram-positive bacteria produced bacteriocins selected from the
group consisting of: acidocin; actagardine; bovicin; brochocin;
butyrivibriocin; carnobacteriocin; carnocin; carnocyclin;
circularin; closticin; coagulin; curvacin; curvaticin; cytolysin;
divercin; divergicin; duramycin; enterocin; entianin; epicidin;
epidermin; epilancin; ericin; gallidermin; garvicin; gassericin;
haloduracin; hiracin; hominicin; ipomicin; lactacin; lactoccin;
lactocyclin; lantibiotic; leucocin; lichenicidin; listeriocin;
lysostaphin; mesentericin; microbisporicin; mundticin; mutacin;
nisin; paenibacillin; pediocin; pep5 lantibiotic; piscicolin;
plantaricin; sakacin; salivaricin; smb; staphylococcin; and any
combination thereof.
19. The method of claim 16, wherein the bacteriocins are
gram-negative bacteria produced bacteriocins selected from the
group consisting of: capistruin; colicin; microcin; pyrocin;
serracin; and any combination thereof.
20. The method of claim 16, wherein the bacteriocins are
gram-positive bacteria produced bacteriocins and gram-negative
bacteria produced bacteriocins and are in a combined presence of
about 0.1 .mu.g/ml to about 300 .mu.g/ml of the wellbore treatment
fluid.
Description
BACKGROUND
[0001] The present invention relates to methods for combating
biological contamination in a wellbore or surrounding subterranean
formation and in wellbore operation fluids using bacteriocins.
[0002] Oil well stimulation, drilling, recovery, and cleanup
operations are often negatively affected by the presence of
bacterial contaminants. These contaminants may be present in the
liquid treatment fluids or equipment (e.g., tanks, pumps,
structural members, etc.) used for well operations, the
subterranean formation itself, or flowback fluids. Bacterial
contaminants may cause numerous problems, such as increased
corrosion rates and plugging of conduits, filters, and pumps,
reservoir souring, etc. They may additionally interfere with the
desired operational qualities of a particular liquid treatment
fluid or additive within the treatment fluid. Some bacteria release
enzymes that degrade polymers commonly used in well operations and
interfere with those operations. For example, degradation of a gel
stabilizer polymer in a treatment fluid could result in a loss in
viscosity of the fluid and decrease in ability of the fluid to
effectively transport necessary additives. Therefore, it is often
desirable to inhibit microbial growth in liquids and substrates
(e.g., metal equipment that comes into contact with the liquids) in
well operations.
[0003] A number of methods have been used for reducing or
eliminating bacterial contaminants in well operations, such as
introducing biocides downhole or using biocides to sterilize
flowback fluids. However, biocides pose significant risk to human
health and the environment. Great care is required when handling
biocides, necessitating appropriate protective clothing and
hazardous disposal practices. Additionally, biocides may have
severe and lasting impacts on water sources and ecosystems, which
may be a particular problem should a well operation fail or the
recovered liquids become uncontained. Bacterial contaminants have
also been mitigated by irradiation of well operation treatment
fluids and flowback fluids with ultraviolet light ("UV"). UV
irradiation is safer to use than biocides for controlling bacterial
contamination. However, UV irradiation requires special UV light
sources at the well site and may not effectively kill bacterial
contaminants. For example, even if UV irradiation wholly eradicates
all bacterial contaminants from well operation fluids or equipment,
any contaminants in the wellbore itself still remain and may
propagate in the treatment fluids after they are introduced.
Moreover, well operation equipment may house bacterial contaminants
and introduce those contaminants into already irradiated treatment
fluids. Therefore, a method of effectively inhibiting bacterial
contaminants in well operations that is safe for human handling and
the environment may be beneficial to one of ordinary skill in the
art.
SUMMARY OF THE INVENTION
[0004] The present invention relates to methods for combating
biological contamination in a wellbore or surrounding subterranean
formation and in wellbore operation fluids using bacteriocins.
[0005] In some embodiments, the present invention provides a method
comprising: providing a portion of a subterranean formation having
a first formation bacterial count as a result of the presence of a
plurality of bacteria in the formation; providing a wellbore
treatment fluid having a first wellbore treatment fluid bacterial
count as a result of the presence of a plurality of bacteria in the
wellbore treatment fluid; combining the wellbore treatment fluid
with a a plurality of bacteriocins; placing the wellbore treatment
fluid into a wellbore in the portion of the subterranean formation;
reducing the first formation bacterial count to a second formation
bacterial count; and reducing the first wellbore treatment fluid
bacterial count to a second wellbore treatment fluid bacterial
count.
[0006] In other embodiments, the present invention provides a
method comprising: providing a portion of a subterranean formation;
providing a flowback fluid that has previously been present in a
portion of a subterranean formation; wherein the flowback fluid has
a first bacterial count as a result of the presence of a plurality
of bacteria; combining the flowback fluid with a plurality of
bacteriocins; and reducing the first bacterial count to a second
bacterial count.
[0007] In still other embodiments, the present invention provides a
method comprising: providing a portion of a subterranean formation
having a first formation bacterial count as a result of the
presence of a plurality of bacteria in the formation; providing a
wellbore treatment fluid having a first wellbore treatment fluid
bacterial count as a result of the presence of a plurality of
bacteria in the wellbore treatment fluid; providing particulates
having a coating of bacteriocins thereon and a coating of
degradable material atop of the coating of bacteriocins; wherein
the degradable coating is a polysaccharide, a cellulose, a chitin,
a chitosan, a protein, an aliphatic polyester, a poly(lactide), a
poly(glycolide), a poly(.epsilon.-caprolactone), a
poly(hydrobutyrate), a poly(anhydride), an aliphatic polycarbonate,
a poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a
poly(vinylidene chloride), a polyphosphazene, or a combination
thereof combining the wellbore treatment fluid with a plurality of
bacteriocins; combining the wellbore treatment fluid with the
coated particulates; placing the wellbore treatment fluid
comprising the coated particulates into a portion of the
subterranean formation; releasing the bacteriocins as the
degradable coating degrades; reducing the first formation bacterial
count to a second formation bacterial count; and reducing the first
wellbore treatment fluid bacterial count to a second wellbore
treatment fluid bacterial count.
[0008] 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.
DETAILED DESCRIPTION
[0009] The present invention relates to methods for combating
biological contamination in a wellbore or surrounding subterranean
formation using bacteriocins. The methods of the various
embodiments of the present invention may combat biological
contamination in a wellbore and flowback fluids, while reducing or
eliminating reliance on hazardous biocides or less effective
antibacterial treatments.
[0010] In some embodiments, the methods disclosed herein may be
used in any type of hydrocarbon recovery operation where
disinfecting a treatment fluid or formation face is desired,
including, but not limited to, pipeline operations, well servicing
operations, upstream exploration and production operations,
downstream refining, processing, storage and transportation
applications, and sterilization of flowback fluids.
[0011] As used herein, the term "bacteriocin" refers to a protein
or peptide produced by a gram-positive or a gram-negative bacterium
that is bactericidal and/or bacteriostatic against organisms
related to the producer bacterium, but that does not act against
the producer bacterium itself. Bacteriocins, thus, are naturally
occurring antibacterial agents. Additionally, bacteriocins are
generally produced by non-pathogenic bacteria naturally found in
the human body. Therefore, they are prime candidates for medicinal
and food-related applications and are safe for human consumption.
Indeed, the bacteriocin nisin is listed as a Generally Recognized
as Safe by the U.S. Food and Drug Administration. The present
invention relates to a novel use of bacteriocins in well
operations. Not only are bacteriocins useful as an antibacterial
agent, they are also generally categorized as food-grade, ensuring
that any inadvertent exposure to the bacteriocins would not be
hazardous to flora, fauna, or human life.
[0012] The wellbore treatment fluids of the present invention may
be any suitable treatment fluids capable of use in a well
operation. Suitable treatment fluids may include, but are not
limited to, aqueous-based fluids, aqueous-miscible fluids,
water-in-oil emulsions, or oil-in-water emulsions. Suitable
aqueous-based fluids may include fresh water, saltwater (e.g.,
water containing one or more salts dissolved therein), brine (e.g.,
saturated salt water), seawater, and any combination thereof.
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. Suitable water-in-oil
emulsions, also known as invert emulsions, may have an oil-to-water
ratio from a lower limit of greater than about 50:50, 55:45, 60:40,
65:35, 70:30, 75:25, or 80:20 to an upper limit of less than about
100:0, 95:5, 90:10, 85:15, 80:20, 75:25, 70:30, or 65:35 by volume
in the base fluid, where the amount may range from any lower limit
to any upper limit and encompass any subset therebetween. Examples
of suitable invert emulsions include those disclosed in U.S. Pat.
Nos. 5,905,061, 5,977,031, 6,828,279, 7,534,745, 7,645,723, and
7,696,131, each of which are incorporated in their entirety herein
by reference. It should be noted that for water-in-oil and
oil-in-water emulsions, any mixture of the above may be used
including the water being and/or comprising an aqueous-miscible
fluid.
[0013] The wellbore treatment fluids of the present invention may
additionally contain an additive or combination of additives
including, but not limited to, a salt, a weighting agent, an inert
solid, a fluid loss control agent, an emulsifier, a dispersion aid,
a corrosion inhibitor, an emulsion thinner, an emulsion thickener,
a viscosifying agent, a gelling agent, a surfactant, a particulate,
a proppant, a gravel particulate, a lost circulation material, a
foaming agent, a gas, a pH control additive, a breaker, a biocide,
a crosslinker, a stabilizer, a chelating agent, a scale inhibitor,
a gas hydrate inhibitor, a mutual solvent, an oxidizer, a reducer,
a friction reducer, a clay stabilizing agent, and any combination
thereof.
[0014] The wellbore treatment fluids of the present invention may
include drilling fluids, lost circulation fluids, stimulation
fluids, sand control fluids, completion fluids, acidizing fluids,
scale inhibiting fluids, water-blocking fluids, clay stabilizer
fluids, fracturing fluids, frac-packing fluids, gravel packing
fluids, wellbore strengthening fluids, acidizing fluids, and sag
control fluids. The methods and compositions of the present
invention may be used in full-scale fluids or as pills. As used
herein, a "pill" is a type of relatively small volume of specially
prepared treatment fluid placed or circulated in the wellbore.
[0015] In some embodiments, the present invention provides a method
comprising: providing a portion of a subterranean formation having
a first formation bacterial count as a result of the presence of a
plurality of bacteria in the formation; providing a wellbore
treatment fluid having a first wellbore treatment fluid bacterial
count as a result of the presence of a plurality of bacteria in the
wellbore treatment fluid; combining the wellbore treatment fluid
with a a plurality of bacteriocins; placing the wellbore treatment
fluid into a wellbore in the portion of the subterranean formation;
reducing the first formation bacterial count to a second formation
bacterial count; and reducing the first wellbore treatment fluid
bacterial count to a second wellbore treatment fluid bacterial
count.
[0016] Because of the mechanism through which bacteriocins work,
gram-positive produced bacteriocins generally, but not always,
serve as a bactericide to gram-positive bacteria and gram-negative
produced bacteriocins generally serve as a bactericide
gram-negative bacteria. Depending on the conditions of the
environment, treatment fluid, wellbore conditions, and other well
operation parameters, gram-positive bacteriocins, gram-negative
bacteriocins, or a combination of both may be used in accordance
with the present invention to inhibit bacterial growth.
[0017] Suitable gram-positive bacteriocins include, but are not
limited to, acidocin; actagardine; bovicin; brochocin;
butyrivibriocin; carnobacteriocin; carnocin; carnocyclin;
circularin; closticin; coagulin; curvacin; curvaticin; cytolysin;
divercin; divergicin; duramycin; enterocin; entianin; epicidin;
epidermin; epilancin; ericin; gallidermin; garvicin; gassericin;
haloduracin; hiracin; hominicin; ipomicin; lactacin; lactoccin;
lactocyclin; lantibiotic; leucocin; lichenicidin; listeriocin;
lysostaphin; mesentericin; microbisporicin; mundticin; mutacin;
nisin; paenibacillin; pediocin; pep5 lantibiotic; piscicolin;
plantaricin; sakacin; salivaricin; smb; staphylococcin; and any
combination thereof. Suitable gram-negative bacteriocins include,
but are not limited to, capistruin; colicin; microcin; pyrocin;
serracin; and any combination thereof. Any gram-positive
bacteriocin may be combined with any gram-negative bacteriocin to
produce the desired effects for a particular well operation. In
some embodiments, the bacteriocin is present in the wellbore
treatment fluid in an amount from about 0.1 .mu.g/ml to about 300
.mu.g/ml. In preferred embodiments, the bacteriocin is present in
the wellbore treatment fluid in an amount from about 0.1 .mu.g/ml
to about 100 .mu.g/ml.
[0018] Bacterial contamination in a well operation may exist in the
treatment fluids themselves or the well (e.g., the subterranean
formation). The treatment fluids containing bacteriocins of the
present invention may serve as a bactericide to both because the
bacteriocins may be effective against any surface which the
treatment fluid contacts.
[0019] The bacteriocins may additionally be used to treat flowback
fluids for bacterial contamination. In some embodiments, the
present invention provides a method comprising: providing a portion
of a subterranean formation; providing a flowback fluid that has
previously been present in a portion of a subterranean formation;
wherein the flowback fluid has a first bacterial count as a result
of the presence of a plurality of bacteria; combining the flowback
fluid with a plurality of bacteriocins; and reducing the first
bacterial count to a second bacterial count.
[0020] As used herein, the term "flowback fluid" refers to any
fluids that flow from a wellbore following treatment with a
wellbore treatment fluid, either in preparation for a subsequent
phase of treatment or in preparation for cleanup. Flowback fluids
may be any wellbore treatment fluid disclosed herein, including any
additive or additives included therein, that flow from the wellbore
and to the surface. Additionally, Flowback fluids may include
produced water or other fluids from the formation, but does not
include produced fluids that are obtained during well production
(e.g., hydrocarbons).
[0021] Some well operations take place under conditions having
extreme pH or temperature levels. Although any suitable buffering
agent that does not interfere with the particular well operation
may be used in accordance with the present invention to control pH,
particular bacteriocins are able to operate at extreme pH levels.
For example, enterocin may be stable at low pH levels (2.0-5.0) and
carnobacterium may be stable at high pH levels (8.5-9.5). Like pH,
bacteriocins are also able to operate at extreme temperatures. For
example, bacteriocins produced by Lactobacillus plantarum are
thermotolerant at 100.degree. C. for at least 90 minutes and
121.degree. C. for at least 20 minutes. (Parada et al., Brazilian
Archives of Bio. & Tech. 50:521-542 (2007)).
[0022] Bacteriocin activity may be enhanced by the use of a
chelating agent and/or a surfactant in combination with the
bacteriocin. The use of a chelating agent and/or a surfactant in
combination with a bacteriocin can enhance the potency and range of
the bacteriocin as a bactericide. Suitable chelating agents
include, but are not limited to EDTA, CaEDTA, CaNa.sub.2EDTA,
alkyldiamine tetraacetates, EGTA, citrate, and any combination
thereof. In some embodiments, the chelating agent is present in an
amount from about 0.1 mM to about 30 mM of the wellbore treatment
fluid or flowback fluid. The surfactants used in the present
invention may be ionic or nonionic. Suitable ionic surfactants
include, but are not limited to emulsifiers, fatty acids,
quaternary compounds, anionic surfactants (e.g., sodium dodecyl
sulphate), amphoteric surfactants (e.g., cocamidopropyl betaine),
and any combination thereof. Suitable nonionic surfactants include,
but are not limited to, polyoxyalkylphenols (e.g., Triton X-100),
polyoxyalkysorbitans (e.g., Tweens), glycerides (e.g., monolaurin
and dioleates), and any combination thereof. In some embodiments,
one or more surfactants are present in the wellbore treatment
fluids and/or flowback fluids of the present invention in an amount
from about 0.01% to about 5.0% of the wellbore treatment fluids. In
other embodiments, the surfactants are present from about 0.1% to
about 1.0% of the wellbore treatment fluids and/or flowback
fluids.
[0023] In some embodiments, the present invention provides a method
comprising: providing a portion of a subterranean formation having
a first formation bacterial count as a result of the presence of a
plurality of bacteria in the formation; providing a wellbore
treatment fluid having a first wellbore treatment fluid bacterial
count as a result of the presence of a plurality of bacteria in the
wellbore treatment fluid; providing particulates having a coating
of bacteriocins thereon and a coating of degradable material atop
of the coating of bacteriocins; wherein the degradable coating is a
polysaccharide, a cellulose, a chitin, a chitosan, a protein, an
aliphatic polyester, a poly(lactide), a poly(glycolide), a
poly(.epsilon.-caprolactone), a poly(hydrobutyrate), a
poly(anhydride), an aliphatic polycarbonate, a poly(orthoester), a
poly(amino acid), a poly(ethylene oxide), a poly(vinylidene
chloride), a polyphosphazene, or a combination thereof combining
the wellbore treatment fluid with a plurality of bacteriocins;
combining the wellbore treatment fluid with the coated
particulates; placing the wellbore treatment fluid comprising the
coated particulates into a portion of the subterranean formation;
releasing the bacteriocins as the degradable coating degrades;
reducing the first formation bacterial count to a second formation
bacterial count; and reducing the first wellbore treatment fluid
bacterial count to a second wellbore treatment fluid bacterial
count.
[0024] In such embodiments, the bacteriocins may be advantageously
delivered to a desired location in a subterranean formation along
with particulates (such as proppant or gravel). In these
particulate embodiments, it may be desirable to coat at least a
portion of the particulates with bacteriocins absorbed thereon with
a degradable coating that will degrade over time and thus release
the bacteriocins over time. Suitable degradable coatings include
degradable polymers, waxes, and latexes. Degradable polymers
suitable for use in the present invention are capable of undergoing
an irreversible degradation down hole. The term "irreversible" as
used herein means that the degradable material, once degraded down
hole, should not recrystallize or reconsolidate while down hole,
e.g., the degradable material should degrade in situ but should not
recrystallize or reconsolidate in situ. The terms "degradation" or
"degradable" refer to both the two relatively extreme cases of
hydrolytic degradation that the degradable material may undergo,
i.e., heterogeneous (or bulk erosion) and homogeneous (or surface
erosion), and any stage of degradation in between these two. This
degradation can be a result of a physical change, chemical process,
or a thermal process. Suitable examples of degradable polymers that
may be used in accordance with the present invention include, but
are not limited to, polysaccharides; cellulose; chitins; chitosans;
proteins; aliphatic polyesters; poly(lactides); poly(glycolides);
poly(.epsilon.-caprolactones); poly(hydroxybutyrates);
poly(anhydrides); aliphatic polycarbonates; poly(orthoesters);
poly(amino acids); poly(ethylene oxides); poly(vindylidene
chloride); and polyphosphazenes. Of these suitable polymers,
aliphatic polyesters and polyanhydrides may be preferred.
Additional detail regarding acceptable degradable polymers can be
found in U.S. Pat. No. 7,044,220, the entire disclosure of which is
hereby incorporated by reference.
[0025] In still other embodiments, the bacteriocins may be coated
directly onto a solid fluid loss control agents used in a
subterranean treatment fluid. By placing the bacteriocins onto
fluid loss control particles, the methods of the present invention
are able to place the bacteriocins directly at, for example, a
fracture face, thus potentially stopping the influx of harmful
bacteria before they reach producing zones. Any solid fluid loss
control agent known in the art may be used to deliver the
bacteriocins in these embodiments of the present invention. Some
common fluid loss control agents include silica, mica, calcite,
aliphatic polyester, polylactic acid, a poly(lactide), a
poly(orthoester), a surfactant-based fluid loss control agent (such
as those described in U.S. Pat. No. 7,413,013, the entire
disclosure of which is hereby incorporated by reference),
carboxymethylcellulose, carboxyethylcellulose, and
polyacrylates.
[0026] Once of skill in the art will recognize that where a coated
particulate embodiment of the present invention is used, a
chelating agent and/or a surfactant may be combined with the
bacteriocin before it is coated onto the particulate.
[0027] 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.
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