US20140090833A1 - Methods for Treating Wellbore and Wellbore Operation Fluids - Google Patents
Methods for Treating Wellbore and Wellbore Operation Fluids Download PDFInfo
- Publication number
- US20140090833A1 US20140090833A1 US13/629,664 US201213629664A US2014090833A1 US 20140090833 A1 US20140090833 A1 US 20140090833A1 US 201213629664 A US201213629664 A US 201213629664A US 2014090833 A1 US2014090833 A1 US 2014090833A1
- Authority
- US
- United States
- Prior art keywords
- bacteriocins
- treatment fluid
- wellbore treatment
- bacterial count
- combination
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
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- MRUAUOIMASANKQ-UHFFFAOYSA-N cocamidopropyl betaine Chemical compound CCCCCCCCCCCC(=O)NCCC[N+](C)(C)CC([O-])=O MRUAUOIMASANKQ-UHFFFAOYSA-N 0.000 description 1
- 229940073507 cocamidopropyl betaine Drugs 0.000 description 1
- 238000010276 construction Methods 0.000 description 1
- 230000009089 cytolysis Effects 0.000 description 1
- 230000000249 desinfective effect Effects 0.000 description 1
- 239000006185 dispersion Substances 0.000 description 1
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- 229940079593 drug Drugs 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 239000004088 foaming agent Substances 0.000 description 1
- 235000013305 food Nutrition 0.000 description 1
- 239000013505 freshwater Substances 0.000 description 1
- 239000003349 gelling agent Substances 0.000 description 1
- 235000021472 generally recognized as safe Nutrition 0.000 description 1
- 235000011187 glycerol Nutrition 0.000 description 1
- 150000002314 glycerols Chemical class 0.000 description 1
- 150000002334 glycols Chemical class 0.000 description 1
- 230000036541 health Effects 0.000 description 1
- 230000003301 hydrolyzing effect Effects 0.000 description 1
- 230000004941 influx Effects 0.000 description 1
- 229940072205 lactobacillus plantarum Drugs 0.000 description 1
- 230000002045 lasting effect Effects 0.000 description 1
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- 229910052751 metal Inorganic materials 0.000 description 1
- 239000002184 metal Substances 0.000 description 1
- NMJORVOYSJLJGU-UHFFFAOYSA-N methane clathrate Chemical compound C.C.C.C.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O NMJORVOYSJLJGU-UHFFFAOYSA-N 0.000 description 1
- 239000010445 mica Substances 0.000 description 1
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- 239000003129 oil well Substances 0.000 description 1
- 239000007800 oxidant agent Substances 0.000 description 1
- 239000002245 particle Substances 0.000 description 1
- 229920000058 polyacrylate Polymers 0.000 description 1
- 239000004626 polylactic acid Substances 0.000 description 1
- 229920005862 polyol Polymers 0.000 description 1
- 150000003077 polyols Chemical class 0.000 description 1
- 229920000136 polysorbate Polymers 0.000 description 1
- 235000011056 potassium acetate Nutrition 0.000 description 1
- WFIZEGIEIOHZCP-UHFFFAOYSA-M potassium formate Chemical compound [K+].[O-]C=O WFIZEGIEIOHZCP-UHFFFAOYSA-M 0.000 description 1
- 239000004323 potassium nitrate Substances 0.000 description 1
- 235000010333 potassium nitrate Nutrition 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 108090000765 processed proteins & peptides Proteins 0.000 description 1
- 238000012545 processing Methods 0.000 description 1
- 230000001681 protective effect Effects 0.000 description 1
- ARIWANIATODDMH-UHFFFAOYSA-N rac-1-monolauroylglycerol Chemical compound CCCCCCCCCCCC(=O)OCC(O)CO ARIWANIATODDMH-UHFFFAOYSA-N 0.000 description 1
- 238000007670 refining Methods 0.000 description 1
- 239000004576 sand Substances 0.000 description 1
- 229920006395 saturated elastomer Polymers 0.000 description 1
- 239000002455 scale inhibitor Substances 0.000 description 1
- 239000013535 sea water Substances 0.000 description 1
- 239000000377 silicon dioxide Substances 0.000 description 1
- 239000001632 sodium acetate Substances 0.000 description 1
- 235000017281 sodium acetate Nutrition 0.000 description 1
- 229910000029 sodium carbonate Inorganic materials 0.000 description 1
- 239000011780 sodium chloride Substances 0.000 description 1
- HLBBKKJFGFRGMU-UHFFFAOYSA-M sodium formate Chemical compound [Na+].[O-]C=O HLBBKKJFGFRGMU-UHFFFAOYSA-M 0.000 description 1
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- 239000004317 sodium nitrate Substances 0.000 description 1
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Classifications
-
- A—HUMAN NECESSITIES
- A01—AGRICULTURE; FORESTRY; ANIMAL HUSBANDRY; HUNTING; TRAPPING; FISHING
- A01N—PRESERVATION OF BODIES OF HUMANS OR ANIMALS OR PLANTS OR PARTS THEREOF; BIOCIDES, e.g. AS DISINFECTANTS, AS PESTICIDES OR AS HERBICIDES; PEST REPELLANTS OR ATTRACTANTS; PLANT GROWTH REGULATORS
- A01N63/00—Biocides, pest repellants or attractants, or plant growth regulators containing microorganisms, viruses, microbial fungi, animals or substances produced by, or obtained from, microorganisms, viruses, microbial fungi or animals, e.g. enzymes or fermentates
- A01N63/50—Isolated enzymes; Isolated proteins
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/02—Well-drilling compositions
- C09K8/03—Specific additives for general use in well-drilling compositions
- C09K8/035—Organic additives
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/605—Compositions for stimulating production by acting on the underground formation containing biocides
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B37/00—Methods or apparatus for cleaning boreholes or wells
- E21B37/06—Methods or apparatus for cleaning boreholes or wells using chemical means for preventing or limiting, e.g. eliminating, the deposition of paraffins or like substances
Definitions
- the present invention relates to methods for combating biological contamination in a wellbore or surrounding subterranean formation and in wellbore operation fluids using bacteriocins.
- 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.
- liquid treatment fluids or equipment e.g., tanks, pumps, structural members, etc.
- 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.
- 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.
- UV ultraviolet light
- UV irradiation requires special UV light sources at the well site and may not effectively kill bacterial contaminants.
- any contaminants in the wellbore itself still remain and may propagate in the treatment fluids after they are introduced.
- 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.
- the present invention relates to methods for combating biological contamination in a wellbore or surrounding subterranean formation and in wellbore operation fluids using bacteriocins.
- 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.
- 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.
- 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( ⁇ -caprolactone), a poly(hydrobutyrate), a poly(anhydride), an aliphatic polycarbonate, a poly(orthoester), a poly(amin
- 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.
- 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.
- 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.
- 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,
- 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.
- suitable invert emulsions include those disclosed in U.S. Pat. Nos.
- 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.
- additives including, but not limited to, a salt, a weighting agent, an inert solid, a fluid loss control agent
- 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.
- a “pill” is a type of relatively small volume of specially prepared treatment fluid placed or circulated in the wellbore.
- 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.
- 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.
- gram-positive bacteriocins, gram-negative bacteriocins, or a combination of both may be used in accordance with the present invention to inhibit bacterial growth.
- 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; ped
- 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.
- the bacteriocin is present in the wellbore treatment fluid in an amount from about 0.1 ⁇ g/ml to about 300 ⁇ g/ml. In preferred embodiments, the bacteriocin is present in the wellbore treatment fluid in an amount from about 0.1 ⁇ g/ml to about 100 ⁇ g/ml.
- 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.
- the bacteriocins may additionally be used to treat flowback fluids for bacterial contamination.
- 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.
- 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).
- bacteriocins are able to operate at extreme pH levels.
- 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).
- bacteriocins are also able to operate at extreme temperatures.
- bacteriocins produced by Lactobacillus plantarum are thermotolerant at 100° C. for at least 90 minutes and 121° C. for at least 20 minutes. (Parada et al., Brazilian Archives of Bio. & Tech. 50:521-542 (2007)).
- 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 2 EDTA, alkyldiamine tetraacetates, EGTA, citrate, and any combination thereof.
- 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.
- 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.
- 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( ⁇ -caprolactone), a poly(hydrobutyrate), a poly(anhydride), an aliphatic polycarbonate, a poly(orthoester), a poly(amino
- the bacteriocins may be advantageously delivered to a desired location in a subterranean formation along with particulates (such as proppant or gravel).
- particulates such as proppant or gravel.
- 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.
- degradable 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.
- 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 include, but are not limited to, polysaccharides; cellulose; chitins; chitosans; proteins; aliphatic polyesters; poly(lactides); poly(glycolides); poly( ⁇ -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.
- the bacteriocins may be coated directly onto a solid fluid loss control agents used in a subterranean treatment fluid.
- a solid fluid loss control agent used in a subterranean treatment fluid.
- 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.
- a chelating agent and/or a surfactant may be combined with the bacteriocin before it is coated onto the particulate.
- 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.
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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.
Description
- The present invention relates to methods for combating biological contamination in a wellbore or surrounding subterranean formation and in wellbore operation fluids using bacteriocins.
- 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.
- 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.
- The present invention relates to methods for combating biological contamination in a wellbore or surrounding subterranean formation and in wellbore operation fluids using bacteriocins.
- 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.
- 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.
- 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(ε-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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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 μg/ml to about 300 μg/ml. In preferred embodiments, the bacteriocin is present in the wellbore treatment fluid in an amount from about 0.1 μg/ml to about 100 μg/ml.
- 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.
- 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.
- 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).
- 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° C. for at least 90 minutes and 121° C. for at least 20 minutes. (Parada et al., Brazilian Archives of Bio. & Tech. 50:521-542 (2007)).
- 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, CaNa2EDTA, 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.
- 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(ε-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.
- 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(ε-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.
- 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.
- 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.
- 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.
Claims (20)
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; CaNa2EDTA; 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; CaNa2EDTA; 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(ε-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 μg/ml to about 300 μg/ml of the wellbore treatment fluid.
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| CA2882949A CA2882949A1 (en) | 2012-09-28 | 2013-09-26 | Well treatment fluid comprising bacteriocins and method of using same for combating biological contamination |
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| EP13841298.6A EP2900784A4 (en) | 2012-09-28 | 2013-09-26 | Methods for treating wellbore and wellbore operation fluids |
| MX2015003020A MX2015003020A (en) | 2012-09-28 | 2013-09-26 | Methods for treating wellbore and wellbore operation fluids. |
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| WO2019014061A1 (en) | 2017-07-12 | 2019-01-17 | Dow Global Technologies, Llc | Compositions and methods for remediation of sulfate reducing prokaryotes |
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Cited By (11)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US9365625B1 (en) | 2011-03-31 | 2016-06-14 | David Gordon Bermudes | Bacterial methionine analogue and methionine synthesis inhibitor anticancer, antiinfective and coronary heart disease protective microcins and methods of treatment therewith |
| US20180208822A1 (en) * | 2015-08-10 | 2018-07-26 | Baker Hughes, A Ge Company, Llc | Proteins for removing sulfurous compounds and/or acidic compounds in downhole fluids |
| US10947433B2 (en) * | 2015-08-10 | 2021-03-16 | Baker Hughes Holdings Llc | Proteins for removing sulfurous compounds and/or acidic compounds in downhole fluids |
| WO2017048320A1 (en) * | 2015-09-14 | 2017-03-23 | M-I L.L.C. | Methods of microbial measuring and control |
| US20180179858A1 (en) * | 2015-09-14 | 2018-06-28 | M-I L.L.C. | Methods of Microbial Measuring and Control |
| GB2558802A (en) * | 2015-09-14 | 2018-07-18 | Mi Llc | Methods of microbial measuring and control |
| US10513910B2 (en) * | 2015-09-14 | 2019-12-24 | M-I L.L.C. | Methods of microbial measuring and control |
| GB2558802B (en) * | 2015-09-14 | 2021-10-27 | Mi Llc | Methods of microbial measuring and control |
| WO2019014061A1 (en) | 2017-07-12 | 2019-01-17 | Dow Global Technologies, Llc | Compositions and methods for remediation of sulfate reducing prokaryotes |
| WO2023122947A1 (en) * | 2021-12-28 | 2023-07-06 | 大连理工大学 | Environmentally-friendly natural gas hydrate inhibitor and application |
| US20230272264A1 (en) * | 2021-12-28 | 2023-08-31 | Dalian University Of Technology | Environmentally friendly natural gas hydrate inhibitor and application |
Also Published As
| Publication number | Publication date |
|---|---|
| EP2900784A4 (en) | 2016-06-01 |
| EP2900784A1 (en) | 2015-08-05 |
| WO2014052519A1 (en) | 2014-04-03 |
| CA2882949A1 (en) | 2014-04-03 |
| AU2013323554A1 (en) | 2015-03-19 |
| MX2015003020A (en) | 2015-11-09 |
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