SYSTEMS AND METHODS TO DEPLOY A CHEMICAL INHIBITOR IN AN OIL OR GAS WELL

Abstract

The disclosure relates to systems and methods to deploy a chemical inhibitor (e.g., a scale inhibitor, a corrosion inhibitor, a biocide, a wax control substance, an asphaltene control substance) in an oil well.

Description

FIELD

The disclosure relates to systems and methods to deploy a chemical inhibitor (e.g., a scale inhibitor, a corrosion inhibitor, a biocide, a wax control substance, an asphaltene control substance) in an oil well.

BACKGROUND

Solid deposition (scale) and corrosion can damage oil and gas production systems. Scale deposits can form on or near a wellbore, perforation or sand face, downhole equipment, production tubular, wellhead, surface flowline, and/or surface oil and gas treating facilities. Scale deposits can restrict hydrocarbon flow, damage equipment, induce localized corrosion, and interfere with oil-water separation. Equipment can be degraded by corrosion due to the presence of acidic gases (e.g., carbon dioxide, hydrogen sulfide) in the produced fluid. Scale inhibitors and corrosion inhibitors can reduce (e.g., prevent) scale formation and corrosion, respectively.

SUMMARY

The disclosure relates to systems and methods to deploy a chemical inhibitor in an oil well. The systems and methods include a support component (e.g., a gauge hanger) and a container attached to the support component. A chemical inhibitor may be disposed within the container. The support component and container may be disposed in a wellbore.

The systems and methods can reduce damage, reduce costs and increase effectiveness of well treatments for scale deposition (e.g., inorganic scale, organic scale), corrosion, microorganism growth, paraffin deposition and/or asphaltene deposition. The systems and methods can further reduce (e.g., prevent) reductions in hydrocarbon flow and production shutdowns and resulting economic losses associated with scale formation.

The systems and methods can be employed, for example, in wells, such as horizontal wells, which do not contain a rathole and/or wells with a relatively small rathole. The systems and methods can be used in hydrocarbon wells producing from low-pressure formations and/or water sensitive reservoir formations.

The systems and methods can allow for the introduction of a chemical inhibitor with reduced operational costs, reduced power and/or reduced maintenance compared to certain other methods of introducing a chemical inhibitor, such as by continuous injection. The systems and methods can introduce a chemical inhibitor with improved concentration control, reduced amounts of chemical inhibitor, reduced number of treatments, reduced (e.g., no) formation damage, and/or reduced (e.g., no) impact to the reservoir pressure relative to certain other methods of introducing a chemical inhibitor, such as by squeeze treatment. The systems and methods can be used in wells producing from a low-pressure reservoir and/or a sensitive reservoir as the systems and methods would cause less (e.g., no) formation damage and decreases in hydrocarbon productivity relative to other methods, such as a squeeze treatment. The systems and methods can permit improved hydrocarbon recovery, relative to certain other systems and methods that may cause formation damage and/or impacts to the reservoir pressure.

In a first aspect, the disclosure provides a system, including a support component and a first container supported by the support component. The first container includes a top face including a plurality of openings, a bottom face including a plurality of openings, a side face, an interior region defined by the top face, the bottom face and the side face, and a first chemical inhibitor disposed in the interior region of the first container.

In some embodiments, the support component includes a gauge hanger.

In some embodiments, the first chemical inhibitor includes a scale inhibitor, a corrosion inhibitor, a biocide, a wax control substance, and/or an asphaltene control substance.

In some embodiments, the first chemical inhibitor includes an encapsulated chemical inhibitor.

In some embodiments, the system further includes a wellbore. The support component and the first container are disposed within the wellbore.

In some embodiments, the wellbore is in fluid communication with an underground reservoir.

In some embodiments, the system is configured so that, during use of the system, a fluid produced from the underground reservoir is in fluid communication with the interior region of the first container so that the fluid interacts with the first chemical inhibitor.

In some embodiments, the system further includes a horizontal well between the underground reservoir and the wellbore so that, during use of the system, the fluid flows through the horizontal well before entering the wellbore.

In some embodiments, the side face of the first container includes a plurality of openings.

In some embodiments, the system further includes a second container supported by the support component. The second container includes a top face including a plurality of openings, a bottom face including a plurality of openings, a side face, an interior region defined by the top face, the bottom face and the side face, and a second chemical inhibitor disposed in the interior region of the second container.

In some embodiments, the second chemical inhibitor includes a scale inhibitor, a corrosion inhibitor, a biocide, a wax control substance, and/or an asphaltene control substance.

In some embodiments, the first container is between the support component and the second container.

In some embodiments, a density of the plurality of openings in the first container is from 4 openings/cm² to 400 openings/cm².

In some embodiments, a diameter of the plurality of openings of in the first container is from 0.5 mm to 5 mm.

In a second aspect, the disclosure provides a method, including disposing a system including a first container supported by a support component into a wellbore, the first container having an interior including a first chemical inhibitor; and flowing a fluid from an underground formation into the interior of the first container so that the fluid interacts with the first chemical inhibitor.

In certain embodiments, the first chemical inhibitor includes a scale inhibitor, a corrosion inhibitor, a biocide, a wax control substance, and/or an asphaltene control substance.

In certain embodiments, the system further includes a second container within the wellbore, the second container being supported by the support component, the second container including a second chemical inhibitor. The fluid is in fluid communication with the second chemical inhibitor during production.

In certain embodiments, the second chemical inhibitor includes a scale inhibitor, a corrosion inhibitor, a biocide, a wax control substance, and/or an asphaltene control substance.

In certain embodiments, the method further includes monitoring a concentration of the first chemical inhibitor in the fluid after the fluid interacts with the first chemical inhibitor.

In certain embodiments, when monitoring the concentration of the first chemical inhibitor results in a determination that a concentration of the first chemical inhibitor in the fluid is below a predetermined level, the method further includes removing the system from the wellbore, disposing additional first chemical inhibitor into the first container, and disposing the system into the wellbore.

In certain embodiments, the method further includes disposing the first container and the support component into the wellbore using a member selected from the group consisting of a slickline or a coiled tubing.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 depicts a schematic of a system.

FIG. 2 depicts a schematic of an encapsulated inhibitor.

FIG. 3 depicts a schematic of a system.

FIG. 4A depicts a schematic of a system.

FIG. 4B depicts a schematic of a system.

FIG. 5 depicts a schematic of a system.

FIG. 6 depicts a schematic of a system.

DETAILED DESCRIPTION

FIG. 1 depicts a system 1000 that includes a gauge hanger 1100 and a container 1200. The container 1200 includes a top face 1220, a bottom face 1240 and a side face 1260. The top face 1220, the bottom face 1240 and the side face 1260 define an interior space of the container 1200.

The gauge hanger 1100 includes an elongated member 1110 with extendable axial protrusions 1112, which allows the system 1000 to be securely anchored in a wellbore. The container 1200 can be attached to the axial protrusion 1112 via a bolted connection. Other appropriate approaches to connecting the container 1200 and the axial protrusion 1112 can be used if desired. The gauge hanger 1100 has a relatively small diameter.

The top face 1220 and the bottom face 1240 of the container 1200 include a plurality of openings (see discussion below regarding FIGS. 4A and 4B). In some embodiments, the side face 1260 includes a plurality of openings 1250. The openings 1250 allow a fluid produced from a wellbore within which the system 1000 is disposed to permeate the container 1200 and subsequently exit the container 1200 (see discussion below regarding FIG. 3).

Generally, the size and/or density of the openings 1250 can be selected as appropriate. In certain embodiments, the size and/or density of the openings 1250 can be determined based on a fluid production rate and/or a desired inhibitor dosage. In some embodiments, the diameter of the openings 1250 is at least 0.5 (e.g., at least 1, at least 1.5, at least 2, at least 2.5, at least 3, at least 3.5, at least 4, at least 4.5) mm and/or at most 5 (e.g., at most 4.5, at most 4, at most 3.5, at most 3, at most 2.5, at most 2, at most 1.5, at most 1) mm. In some embodiments, the openings 1250 have a density of at least 4 (e.g., at least 5, at least 10, at least 20, at least 40, at least 50, at least 100, at least 150, at least 200, at least 250, at least 300, at least 350) openings/cm² and/or at most 400 (e.g., at most 350, at most 300, at most 250, at most 200, at most 150, at most 100, at most 50, at most 40, at most 20, at most 10, at most 5) openings/cm².

In general, the size (e.g., diameter) of the container 1200 can be the same or different from the size (e.g., diameter) of the gauge hanger 1100. A relatively large size (e.g., diameter) and/or length of the container 1200 may be preferred to allow for increased storage in the container 1200 relative to a smaller container. In general, the container 1200 can have any appropriate shape. In some embodiments, the container 1200 is a cylinder. In some embodiments, the diameter of the container 1200 (e.g., in the shape of a cylinder) is determined by the diameter of a wellbore and/or tubing in which the system 1000 is disposed. In some embodiments, the container 1200 (e.g., in the shape of a cylinder) has a diameter of at least 2 (e.g., at least 3, at least 4, at least 5) inches and/or at most 6 (e.g., at most 5, at most 4, at most 3) inches. In some embodiments, the container 1200 (e.g., in the shape of a cylinder) has a length of at least 5 (e.g., at least 10, at least 15, at least 20, at least 25, at least 30, at least 35, at least 40, at least 45, at least 50, at least 55, at least 60, at least 65, at least 70, at least 75, at least 80, at least 85, at least 90, at least 95) feet (ft) and/or at most 100 (e.g., at most 95, at most 90, at most 85, at most 80, at most 75, at most 70, at most 65, at most 60, at most 55, at most 50, at most 45, at most 40, at most 35, at most 30, at most 25, at most 20, at most 15, at most 10) ft. In some embodiments, the volume of the container 1200 is at least 1 (e.g., at least 2, at least 5, at least 10, at least 15, at least 20) ft³ and/or at most 20 (e.g., at most 15, at most 10, at most 5, at most 2) ft³.

In some embodiments, the gauge hanger 1100 has an outer diameter of at least 1.0 (e.g., at least 1.5, at least 2.0) inches and/or at most 2.5 (e.g., at most 2.0, at most 1.5) inches. In some embodiments, the axial protrusions 1112 have a diameter of at least 1.8 (e.g., at least 1.878, at least 1.9, at least 2.0, at least 2.5, at least 3.0, at least 3.5, at least 4.0, at least 4.029) inches and/or at most 4.1 (e.g., at most 4.029, at most 4.0, at most 3.5, at most 3.0, at most 2.5, at most 2.0, at most 1.9, at most 1.878) inches when extended. In some embodiments, the axial protrusions 1112 have a diameter of at least 3.4 (e.g., at least 3.481, at least 3.5, at least 4.0, at least 4.5, at least 5.0, at least 5.5, at least 6.0, at least 6.466) inches and/or at most 6.5 (e.g., at most 6.466, at most 6.4, at most 6.0, at most 5.5, at most 5.0, at most 4.5, at most 4.0, at most 3.5, at most 3.481) inches when extended.

The composition of the container 1200 may be determined based on well conditions such that the container 1200 can withstand the well conditions for a desired period of time without undergoing substantial corrosion/decay. In some embodiments, the container 1200 is be made of stainless steel or a corrosion resistant alloy.

A chemical inhibitor can be disposed in the interior space of the container 1200. In general, the chemical inhibitor can be any suitable solid chemical inhibitor to address a production chemistry problem. Examples of chemical inhibitors include scale inhibitors, corrosion inhibitors, biocides, wax control substances and asphaltene control substances. In some embodiments, two or more (e.g., three or more, four or more, five or more) different chemical inhibitors can be disposed in the interior space of the container 1200.

Examples of scale inhibitors include a polyphosphate, 1-hydroxyethylidenediphosphonic acid (HDEP), ethane-1,2-diphosphonic acid (EDPA), diethylenetriaminepenta(methylenephosphonic acid) (DETPMP), tris(phosphonomethyl)amine, nitrilotrimethylphosphonic acid, aminotris(methylphosphonic acid) (ATMP), bis(hexamethylenetriaminepenta(methylenephosphonic acid)) (BHTMP), 1-hydroxyethylidene-1,1-diphosphonic acid (HEDP), [[(2-hydroxyethyl)imino]bis(methylene)]bisphosphonic acid (MEA/HADMP), polyacrylic acid (PAA), polymaleic acid (PMA), polyphosphinocarboxylic acid (PPCA), polyvinyl sulfonate and polyacrylic acid copolymer (PVS), phosphonocarboxylic acid (POCA) and 2-phosphono-butane-1, 2, 4-tricarboxylic acid (PBTC), polyamino polyether methylene phosphonae (PAPEMP), and polyaspartate.

Examples of corrosion inhibitors include, imidazoline, a primary amine, a secondary amine, a tertiary amine, a quaternary amine, n-dodecylamine, N-N-dimethyl dodecylamine, amide, amidoamine, amidoimidazoline, isoxazolidine, succinic acid, carboxylic acid, aldehyde, alkanolamine, imidazoline-imidazolidine compound, α,β-ethylene unsaturated aldehyde, polyalkylenepolyamine, and diethylenetriamine.

Examples of biocides include glutaraldehyde, tetrakis(hydroxymethyl)phosphonium sulfate (THPS), alkyldimethylbenzylammonium chloride (ADBAC), didecyldimethylammonium chloride (DDAC), tributyl(tetradecyl)phosphonium chloride (TTPC), cocodiamine, 2,2-dibromo-3-nitrilopropionamide (DBNPA), 2-bromo-2-nitro-1,3-propanediol, tetrahydro-3,5-dimethyl-2H-1,3,5-thiadiazinethione, 5-chloro-2-methyl-4-isothiazolin-3-one+2-methyl-4-isothiazolin-3-one (CMIT/MIT), 4,4-dimethyloxazolidine (DMO), 1-(3-chloroallyl)-3,5,7-triaza-1-azoniaadamantane chloride (CTAC), tris(hydroxymethyl)nitromethane (THNM), sodium hypochlorite, ozone, chlorine dioxide, and peracetic acid.

Examples of wax control substances include poly(ethylene-co-vinyl acetate)(EVA), ethylene/acrylonitrile copolymers, poly(ethylene-b-propylene), poly(ethylene butene) polymers, (meth)acrylic acid and maleic anhydride co-polymers, polyesters, amine ethoxylates, alkyl sulfonates, alkyl aryl sulfonates, fatty amine ethoxylates.

Examples of asphaltene control substances include xylene, n-butylisoquinolinium chloride ionic liquid, amphiphil P (n-dodecyl) benzene sulfonic acid, vegetable oil, coconut essential oil, sweet almond, andiroba and sandalwood oil, boscan resins, cerro negro resins, 1-allyl-3-hexadecylimidazolium bromide, dodecyl benzene sulfonic acid (DBSA), dodecyl trimethyl ammonium bromide (DTAB), light cycle oil (LCO), TiO₂ nanoparticles, surfactant (SDJ), nanofluids of Al₂O₃, propoxylated polydodecyl, phenol formaldehyde, octylphenol, dodecyl phenol, and 2-hydroxybenzenecarboxcylic acid (C₆H₄(OH)COOH, salicylic acid).

The chemical inhibitor can include an encapsulated product (chemical inhibitor encapsulated within an encapsulating material) to allow placement of a liquid chemical inhibitor in the container 1200, improve the treatment efficiency and/or extend the treatment lifetime by releasing the chemical inhibitor relatively slowly upon contact with the produced fluid. An encapsulated chemical inhibitor can include, for example, a liquid chemical inhibitor encapsulated in an encapsulating material (e.g., a polymer matrix, a ceramic). The chemical inhibitor can diffuse from the encapsulating material into the produced fluid.

FIG. 2 depicts a schematic of an embodiment of an encapsulated inhibitor aggregate 2000. The encapsulated chemical inhibitor 2010 is disposed in an encapsulating material 2020 (e.g., a polymer matrix). In certain embodiments, an encapsulated inhibitor aggregate 2000, as depicted in FIG. 2, is disposed in the container 1200. The encapsulated chemical inhibitor 2010 can diffuse from an interior space of the encapsulating material 2020 into a space exterior to the encapsulating material 2020 and enter the surrounding produced fluid. Without wishing to be bound by theory, it is believed that, in some embodiments the release of the encapsulated chemical inhibitor 2010 can depend on the interaction with the produced fluids. In some embodiments, capsules of encapsulated chemical inhibitor 2010 have a size of at least 25 (e.g., at least 30, at least 35, at least 40, at least 45, at least 50, at least 55, at least 60, at least 65, at least 70) micrometers (μm) and/or at most 75 (e.g., at most 70, at most 65, at most 60, at most 55, at most 50, at most 45, at most 40, at most 35, at most 30) μm. In some embodiments, the encapsulated inhibitor aggregates 2000 have a size of at least 1 (e.g., at least 1.5, at least 2, at least 2.5) mm and/or at most 3 (e.g., at most 2.5, at most 2, at most 1.5) mm.

Alternatively, in some embodiments, the chemical inhibitor can include particles formed by a precipitation reaction of an active chemical inhibitor ingredient (e.g., the scale inhibitor, the corrosion inhibitor, the biocide, the wax control substance, the asphaltene control substance) and a multivalent cation (e.g., a calcium ion, a magnesium ion, a barium ion, a strontium ion, an aluminum ion). The particles formed by precipitation reaction can be disposed in the container 1200 and dissolve on contact with a produced fluid, thereby releasing the chemical inhibitor. Forming particles by precipitation allows the placement of a liquid chemical inhibitor in the container 1200 without the need for an encapsulating material.

FIG. 3 depicts a system 3000 that includes the system 1000 disposed inside a wellbore 3100. The gauge hanger 1100 of the system 1000 holds the system 1000 at a fixed depth inside the wellbore 3100. In certain embodiments, the container 1200 fits snugly inside the wellbore 3100. One or more chemical inhibitors are disposed within the interior of the container 1200. The wellbore 3100 is in fluid communication with a horizontal well 3200. When a fluid 3300 is produced from the horizontal well 3200 through the wellbore 3100, it permeates the container 1200, thereby creating fluid contact between the fluid 3300 and the chemical inhibitor(s) disposed inside the container 1200. Upon contact, chemical inhibitor can dissolve in the produced fluid 3300 and/or encapsulated chemical inhibitor can diffuse through the encapsulating matrix into the produced fluid 3300. This allows the chemical inhibitor to interact with the produced fluid to address one or more production chemistry problems (e.g., scale deposition, corrosion, microorganism growth, paraffin deposition, asphaltene deposition).

The system 1000 can be installed in the wellbore 3100 using, for example, a slickline or coiled tubing. The depth of the system 1000 in the wellbore 3100 can be determined, for example, using historical well log data and/or model predictions. In certain embodiments, the depth of the system 1000 in the wellbore 3100 is at least 200 (e.g., at least 500, at least 1,000, at least 1,500, at least 2,000, at least 5,000) ft and/or at most 10,000 (e.g., at most 5,000, at most 2,000, at most 1,000, at most 500) ft.

In certain embodiments, the wellbore 3100 has a diameter of at least 1-⅞ (e.g., at least 2, at least 2-½, at least 3, at least 3-½, at most 4) inches and/or at most 4-½ (e.g., at most 4, at most 3-½, at most 3, at most 2-½, at most 2) inches. In certain embodiments, the wellbore 3100 has a diameter of at least 4-½ (e.g., at least at least 5, at least 5-½, at least 6, at least 6-½) inches and/or at most 7 (e.g., at most 6-½, at most 6, at most 5-½, at most 5) inches.

Examples of the produced fluid include produced water and crude oil. In some embodiments, the produced fluid includes an acid gas (e.g., carbon dioxide, hydrogen sulfide), a compound capable of forming scale (e.g., calcium ion, barium ions, bicarbonate ions, sulfate ions), a microorganism, paraffin (high molecular weight alkanes) and/or asphaltene.

The concentration of the chemical inhibitor in the produced fluid 3300 can be monitored from wellhead samples, using, for example, a spectrophotometric method, inductively coupled plasma (ICP), high-performance liquid chromatography (HPLC), or ion chromatography (IC). In some embodiments, when the concentration of the chemical inhibitor falls below a desired value, the system 1000 can be retrieved and replenished with additional chemical inhibitor. The system 1000 can be retrieved using, for example, a slickline or coiled tubing.

FIG. 4A depicts the container 1200 and the produced fluid 3300. The container 1200 includes a plurality of openings 1250 on the top face 1220 and the bottom face 1240 of the container 1200. Produced fluid 3300 can enter the interior space of the container 1200 via the openings 1250 on the bottom face 1240 of the container 1200. After contacting a chemical inhibitor disposed inside the container 1200, the produced fluid 3300 can exit the interior space of the container 1200 via the openings 1250 on the top face 1220 of the container 1200.

FIG. 4B depicts a container 1200′ and a produced fluid 3300. The container 1200′ includes the components of the container 1200, but the container 1200′ also includes a plurality of openings 1250 on upper and lower regions of the side face 1260 of the container 1200′. Produced fluid 3300 can enter the interior space of the container 1200′ via the openings 1250 on the bottom face 1240 and/or the lower region of the side face 1260. After contacting a chemical inhibitor disposed inside the container 1200′, the produced fluid 3300 can exit the interior space of the container 1200′ via the openings 1250 on the top face 1220 and/or the upper region of the side face 1260. Without wishing to be bound by theory, it is believed that including openings 1250 on the upper and lower regions of the side face 1260 of the container 1200′ can increase the amount of produced fluid in contact with the chemical inhibitor disposed within the container 1200′, thereby increasing the concentration of the chemical inhibitor in the produced fluid. It is further believed that this can increase the delivery of a chemical inhibitor to the produced fluid and reduce the impact of a production chemistry problem being addressed.

Although FIG. 3 refers to the container 1200, it is to be understood that the system 3000 could include the container 1200′ instead of the container 1200.

FIG. 5 depicts a system 5000. The system 5000 includes the components of the system 1000. However, unlike the system 1000, the system 5000 includes a container 5200. The container 5200 includes the components of the container 1200. However, rather than being attached to the gauge hanger 1100, the container 5200 is attached to the container 1200. A second chemical inhibitor is disposed in an interior space of the container 5200. The second chemical inhibitor disposed in the interior space of the container 5200 may be different from the chemical inhibitor disposed in the container 1200. In some embodiments, two or more (e.g., three or more, four or more, five or more) different chemical inhibitors can be disposed in the interior space of the container 5200. Although FIG. 5 refers to the container 1200, it is to be understood that the system 5000 could include the container 1200′ instead of the container 1200.

FIG. 6 depicts a system 6000. The system 6000 includes the components of the system 3000. However, unlike the system 3000, the system 6000 includes the system 5000 disposed in the wellbore 3100, rather than the system 1000. When the fluid 3300 is produced from the horizontal well 3200 through the wellbore 3100, it permeates the containers 5200 and 1200, thereby creating fluid contact between the fluid 3300 and the chemical inhibitors disposed inside the containers 5200 and 1200. Although FIG. 6 refers to the container 1200, it is to be understood that the system 6000 could include the container 1200′ instead of the container 1200.

While embodiments have been disclosed that include a gauge hanger, the disclosure is not limited to such embodiments. For example, any suitable support component can be used in the system 1000 and/or 5000, such as a wireline and/or coiled tubing.

Claims

1. A system, comprising:

a support component;

a first container supported by the support component, the first container comprising: a top face comprising a plurality of openings; a bottom face comprising a plurality of openings; a side face; an interior region defined by the top face, the bottom face and the side face; and a first chemical inhibitor disposed in the interior region of the first container.

2. The system of claim 1, wherein the support component comprises a gauge hanger.

3. The system of claim 1, wherein the first chemical inhibitor comprises a member selected from the group consisting of a scale inhibitor, a corrosion inhibitor, a biocide, a wax control substance, and an asphaltene control substance.

4. The system of claim 1, wherein the first chemical inhibitor comprises an encapsulated chemical inhibitor.

5. The system of claim 1, further comprising a wellbore, wherein the support component and the first container are disposed within the wellbore.

6. The system of claim 5, wherein the wellbore is in fluid communication with an underground reservoir.

7. The system of claim 6, wherein the system is configured so that, during use of the system, a fluid produced from the underground reservoir is in fluid communication with the interior region of the first container so that the fluid interacts with the first chemical inhibitor.

8. The system of claim 7, further comprising a horizontal well between the underground reservoir and the wellbore so that, during use of the system, the fluid flows through the horizontal well before entering the wellbore.

9. The system of claim 1, wherein the side face of the first container comprises a plurality of openings.

10. The system of claim 1, further comprising a second container supported by the support component, the second container comprising:

a top face comprising a plurality of openings;

a bottom face comprising a plurality of openings;

a side face;

an interior region defined by the top face, the bottom face and the side face; and

a second chemical inhibitor disposed in the interior region of the second container.

11. The system of claim 10, wherein the second chemical inhibitor comprises a member selected from the group consisting of a scale inhibitor, a corrosion inhibitor, a biocide, a wax control substance, and an asphaltene control substance.

12. The system of claim 10, wherein the first container is between the support component and the second container.

13. The system of claim 1, wherein at least one of the following holds:

a density of the plurality of openings in the first container is from 4 openings/cm2 to 400 openings/cm2; and

a diameter of the plurality of openings of in the first container is from 0.5 mm to 5 mm.

14. A method, comprising:

disposing a system comprising a first container supported by a support component into a wellbore, the first container having an interior comprising a first chemical inhibitor; and

flowing a fluid from an underground formation into the interior of the first container so that the fluid interacts with the first chemical inhibitor.

15. The method of claim 14, wherein the first chemical inhibitor comprises a member selected from the group consisting of a scale inhibitor, a corrosion inhibitor, a biocide, a wax control substance, and an asphaltene control substance.

16. The method of claim 15, wherein the system further comprises a second container within the wellbore, the second container being supported by the support component, the second container comprising a second chemical inhibitor,

wherein the fluid is in fluid communication with the second chemical inhibitor during production.

17. The method of claim 16, wherein the second chemical inhibitor comprises a member selected from the group consisting of a scale inhibitor, a corrosion inhibitor, a biocide, a wax control substance, and an asphaltene control substance.

18. The method of claim 14, wherein the method further comprises monitoring a concentration of the first chemical inhibitor in the fluid after the fluid interacts with the first chemical inhibitor.

19. The method of claim 18, further comprising, when monitoring the concentration of the first chemical inhibitor results in a determination that a concentration of the first chemical inhibitor in the fluid is below a predetermined level:

removing the system from the wellbore;

disposing additional first chemical inhibitor into the first container; and

disposing the system into the wellbore.

20. The method of claim 14, further comprising disposing the first container and the support component into the wellbore using a member selected from the group consisting of a slickline or a coiled tubing.