Online mitigation of a leak in a tubing string of a subterranean wellbore

Abstract

A method for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore includes introducing, from above an entry point of the subterranean wellbore, a sealing material into a cavity of the tubing string within the subterranean wellbore. The sealing material is configured to cover, based on a differential in pressure between the cavity of the tubing string and an annulus between the tubing string and a casing, a hole in a wall in a component of the substantially vertical section of the tubing string. The hole in the wall of the component develops as a result of a failure in the wall during production operations.

Description

TECHNICAL FIELD

[0001] The present application is related to subterranean operations and, more particularly, to online mitigation of a leak in a tubing string of a subterranean wellbore.BACKGROUND

[0002] In production operations, there are times when pressure within a wellbore needs to be raised to extract additional subterranean resources (e.g., oil, natural gas, water) out of the wellbore. One way to raise pressure in the wellbore is through the use of one or more gas lift valves that are integrated with the tubing string. However, gas lift valves often develop leaks or holes, which results in a reduction in wellbore pressure. When these leaks or holes in a gas lift valve occur, the tubing string may be pulled out of the wellbore so that the gas lift valve can be replaced. Alternatively, “packoff” tools can be deployed, but this solution is expensive, has a relatively low rate of success, and restricts the inner diameter of the tubing string, which makes the tubing string difficult to extract. Similar problems exist for tubing pipes in a tubing string.

[0003] Side pocket mandrels (SPMs) may be introduced to overcome some of the issues that exist with traditional mandrels, but there are multiple conditions where a tubing string needs to be pulled because of a malfunction with a SPM. For example, the SPM may have a defect and have a leak around the valve. As another example, over injection may result in failure of a valve in a SPM, which forces the valve to be pulled and replaced by a slickline. Further, remotely operated gas lift valves (ROGLVs) are known to malfunction by remaining open. In addition, traditional valves are known to develop leaks and / or holes, causing failure. On wells with conventional gas lift mandrels, valve failures are fixable by tripping out the tubing string.

[0004] Valves failed in wells with side pocket mandrels as part of the tubing string could be replaced utilizing slickline / wireline operations, replacing the valve only. Still, there are occasions where a valve cannot be pulled due to mandrel failure or foreign materials keeping the valve seized and stuck in a SPM. In that case, the tubing string has to be pulled and replaced to fix the leak. A key performance indicator on gas lifted wells is making the depth of injection as deep as possible. Any shallow leak through a broken or damaged valve, or by a malfunctioning SPM or ROGLV, dramatically reduces gas lift performance, and so it is crucial to stop shallow gas losses when possible.SUMMARY

[0005] In general, in one aspect, the disclosure relates to a method for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore. The method may include introducing, from above an entry point of the subterranean wellbore, a sealing material into a cavity of the tubing string within the subterranean wellbore, where the sealing material is configured to cover, based on a differential in pressure between the cavity of the tubing string and an annulus between the tubing string and a casing, the hole in a wall in a component of the substantially vertical section of the tubing string, and where the hole in the wall of the component develops as a result of a failure in the wall during production operations.

[0006] In another aspect, the disclosure relates to a system for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore. The system may include a sensor device configured to measure a pressure within the subterranean wellbore in an area of the substantially vertical section of the tubing string. The system may also include a receptacle in which a sealing material is disposed, wherein the sealing material is configured to be removed from the receptacle when the pressure measured by the sensor device falls outside a range of acceptable values, where the sealing material is further configured to be introduced, from above an entry point of the subterranean wellbore after being removed from the receptacle, into a cavity of the tubing string within the subterranean wellbore, where the sealing material is further configured to cover, based on a differential in pressure between the cavity of the tubing string and an annulus between the tubing string and a casing, the hole in a wall in a component of the substantially vertical section of the tubing string, and where the hole in the wall of the component develops as a result of a failure in the wall during production operations.

[0007] These and other aspects, objects, features, and embodiments will be apparent from the following description and the appended claims.BRIEF DESCRIPTION OF THE DRAWINGS

[0008] The drawings illustrate only example embodiments and are therefore not to be considered limiting in scope, as the example embodiments may admit to other equally effective embodiments. The elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Additionally, certain dimensions or positions may be exaggerated to help visually convey such principles. In the drawings, reference numerals designate like or corresponding, but not necessarily identical, elements.

[0009] FIG. 1 shows a block diagram of a sample system for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore according to certain example embodiments.

[0010] FIG. 2 shows a sectional view of part of a wellbore with which example embodiments may be used.

[0011] FIG. 3 shows a sectional view of the part of the wellbore of FIG. 2 at a subsequent time when a hole has developed in one of the tubing string components according to certain example embodiments.

[0012] FIG. 4 shows a sectional view of the part of the wellbore of FIG. 3 at a subsequent time when an attempt to cover the hole is being made according to certain example embodiments.

[0013] FIG. 5 shows a sectional view of the part of the wellbore of FIG. 4 at a subsequent time when the hole becomes covered according to certain example embodiments.

[0014] FIG. 6 shows a sectional view of the part of the wellbore of FIG. 5 at a subsequent time when the hole remains covered during production operations according to certain example embodiments.

[0015] FIG. 7 shows a sectional view of the part of the wellbore of FIG. 6 at a subsequent time when the process of using pressure to disintegrate the sealing material covering the hole begins according to certain example embodiments.

[0016] FIG. 8 shows a sectional view of the part of the wellbore of FIG. 7 at a subsequent time when the sealing material has disintegrated using pressure according to certain example embodiments.

[0017] FIG. 9 shows a sectional view of the part of the wellbore of FIG. 6 at a subsequent time when the process of using a chemical additive to disintegrate the sealing material covering the hole begins according to certain example embodiments.

[0018] FIG. 10 shows a sectional view of the part of the wellbore of FIG. 9 at a subsequent time when the process of using a chemical additive to disintegrate the sealing material covering the hole continues according to certain example embodiments.

[0019] FIG. 11 shows a sectional view of the part of the wellbore of FIG. 10 at a subsequent time when the sealing material has disintegrated using the chemical additive according to certain example embodiments.

[0020] FIG. 12 shows a sectional view of the part of the wellbore of FIG. 6 at a subsequent time when the process of using temperature to disintegrate the sealing material covering the hole begins according to certain example embodiments.

[0021] FIG. 13 shows a sectional view of the part of the wellbore of FIG. 12 at a subsequent time when the sealing material has disintegrated using temperature according to certain example embodiments.

[0022] FIG. 14 shows a sectional view of the part of the wellbore of FIG. 6 at a subsequent time when a hole has developed in another of the tubing string components according to certain example embodiments.

[0023] FIG. 15 shows a sectional view of the part of the wellbore of FIG. 14 at a subsequent time when an attempt to cover the additional hole is being made according to certain example embodiments.

[0024] FIG. 16 shows a sectional view of the part of the wellbore of FIG. 15 at a subsequent time when the additional hole becomes covered according to certain example embodiments.

[0025] FIG. 17 shows a sectional view of the part of the wellbore of FIG. 16 at a subsequent time when the original hole becomes uncovered by passage of time according to certain example embodiments.

[0026] FIG. 18 shows a flow chart of a method for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore according to certain example embodiments.

[0027] FIG. 19 shows a section of a substantially vertical section of a tubing string within a subterranean wellbore in which a leak may be mitigated according to certain example embodiments.

[0028] FIG. 20 shows a block diagram of a computer device according to certain example embodiments.

[0029] FIG. 21 shows a sectional view of part of another wellbore with which example embodiments may be used.

[0030] FIG. 22 shows a sectional view of the part of the wellbore of FIG. 21 at a subsequent time when a hole has developed in one of the tubing string components according to certain example embodiments.

[0031] FIG. 23 shows a sectional view of the part of the wellbore of FIG. 22 at a subsequent time when an attempt to cover the hole is being made according to certain example embodiments.

[0032] FIG. 24 shows a sectional view of the part of the wellbore of FIG. 23 at a subsequent time when the hole becomes covered according to certain example embodiments.

[0033] FIG. 25 shows a sectional view of the part of the wellbore of FIG. 24 at a subsequent time when the hole remains covered during production operations according to certain example embodiments.DETAILED DESCRIPTION

[0034] The example embodiments discussed herein are directed to systems, methods, and devices for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore. A wellbore with which example embodiments may be used herein may be located subsea or on land. Example embodiments may be used during any type of field operation, including but not limited to production operations. Example embodiments (including portions thereof) may be rated for use in marine and / or hazardous environments.

[0035] Example embodiments and related systems (e.g., a tubing string, a casing string) can include multiple components that are described herein, where a component can be made from a single piece (as from a mold or an extrusion). When a component (or portion thereof) of an example embodiment for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore, including related systems, is made from a single piece, the single piece can be cut out, bent, stamped, and / or otherwise shaped to create certain features, elements, or other portions of the component. Alternatively, a component (or portion thereof) of an example embodiment for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore, including related systems, can be made from multiple pieces that are mechanically coupled to each other. In such a case, the multiple pieces can be mechanically coupled to each other using one or more of a number of coupling methods, including but not limited to fusion, adhesives, welding, fastening devices, compression fittings, mating threads, and slotted fittings. One or more pieces that are mechanically coupled to each other can be coupled to each other in one or more of a number of ways, including but not limited to fixedly, hingedly, rotatably, removably, slidably, and threadably.

[0036] Components and / or features described herein can include elements that are described as coupling, fastening, securing, or other similar terms. Such terms are merely meant to distinguish various elements and / or features within a component or device and are not meant to limit the capability or function of that particular element and / or feature. For example, a feature described as a “coupling feature” can couple, secure, abut against, fasten, and / or perform other functions aside from merely coupling. In addition, each component and / or feature described herein (including each component of an example system for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore) can be made of one or more of a number of suitable materials, including but not limited to synthetic material, organic material, metal (e.g., stainless steel), ceramic, rubber, glass, and plastic.

[0037] A coupling feature (including a complementary coupling feature) as described herein can allow one or more components (e.g., a housing) and / or portions of an example embodiment for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore to become mechanically coupled, directly or indirectly, to another portion of the example embodiment for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore and / or a component of a larger system. A coupling feature can include, but is not limited to, a portion of mating threads, a hinge, an aperture, a recessed area, a protrusion, a slot, and a detent. One portion of an example system for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore can be coupled to another portion of the example embodiment of a system mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore and / or a component of a larger system by the direct use of one or more coupling features.

[0038] In addition, or in the alternative, a portion of an example embodiment for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore can be coupled to another portion of the example embodiment for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore and / or a component of a larger system using one or more independent devices that interact with one or more coupling features disposed on a component of the example embodiment for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore. Examples of such devices can include, but are not limited to, a fastening device (e.g., a bolt, a screw, a rivet), a pin, a hinge, an adapter, and a spring. One coupling feature described herein can be the same as, or different than, one or more other coupling features described herein. A complementary coupling feature as described herein can be a coupling feature that mechanically couples, directly or indirectly, with another coupling feature.

[0039] When used in certain systems (e.g., for certain subterranean production operations), example embodiments can be designed to help such systems comply with certain standards and / or requirements. Examples of entities that set such standards and / or requirements can include, but are not limited to, the Society of Petroleum Engineers, the American Petroleum Institute (API), the International Standards Organization (ISO), and the Occupational Safety and Health Administration (OSHA). Also, as discussed above, example embodiments for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore can be used in marine and / or hazardous environments, and so example embodiments for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore can be designed to comply with industry standards that apply to marine and / or hazardous environments.

[0040] It is understood that when combinations, subsets, groups, etc. of elements are disclosed (e.g., combinations of components in a composition, or combinations of steps in a method), that while specific reference of each of the various individual and collective combinations and permutations of these elements may not be explicitly disclosed, each is specifically contemplated and described herein. By way of example, if an item is described herein as including a component of type A, a component of type B, a component of type C, or any combination thereof, it is understood that this phrase describes all of the various individual and collective combinations and permutations of these components.

[0041] For example, in some embodiments, the item described by this phrase could include only a component of type A. In some embodiments, the item described by this phrase could include only a component of type B. In some embodiments, the item described by this phrase could include only a component of type C. In some embodiments, the item described by this phrase could include a component of type A and a component of type B. In some embodiments, the item described by this phrase could include a component of type A and a component of type C. In some embodiments, the item described by this phrase could include a component of type B and a component of type C.

[0042] In some embodiments, the item described by this phrase could include a component of type A, a component of type B, and a component of type C. In some embodiments, the item described by this phrase could include two or more components of type A (e.g., A1 and A2). In some embodiments, the item described by this phrase could include two or more components of type B (e.g., B1 and B2). In some embodiments, the item described by this phrase could include two or more components of type C (e.g., C1 and C2). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type A (A1 and A2)), optionally one or more of a second component (e.g., optionally one or more components of type B), and optionally one or more of a third component (e.g., optionally one or more components of type C).

[0043] In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type B (B1 and B2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type C (C1 and C2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type B).

[0044] If a component of a figure is described but not expressly shown or labeled in that figure, the label used for a corresponding component in another figure can be inferred to that component. Conversely, if a component in a figure is labeled but not described, the description for such component can be substantially the same as the description for the corresponding component in another figure. The numbering scheme for the various components in the figures herein is such that each component is a three-digit number or a four-digit number, and corresponding components in other figures have the identical last two digits. For any figure shown and described herein, one or more of the components may be omitted, added, repeated, and / or substituted. Accordingly, embodiments shown in a particular figure should not be considered limited to the specific arrangements of components shown in such figure.

[0045] Further, a statement that a particular embodiment (e.g., as shown in a figure herein) does not have a particular feature or component does not mean, unless expressly stated, that such embodiment is not capable of having such feature or component. For example, for purposes of present or future claims herein, a feature or component that is described as not being included in an example embodiment shown in one or more particular drawings is capable of being included in one or more claims that correspond to such one or more particular drawings herein.

[0046] Example embodiments for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore will be described more fully hereinafter with reference to the accompanying drawings, in which example embodiments for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore are shown. Example embodiments for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore may, however, be embodied in many different forms and should not be construed as limited to the example embodiments set forth herein. Rather, these example embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore to those of ordinary skill in the art. Like, but not necessarily the same, elements (also sometimes called components) in the various figures are denoted by like reference numerals for consistency.

[0047] Terms such as “first”, “second”, “primary,”“secondary,”“above”, “below”, “inner”, “outer”, “distal”, “proximal”, “end”, “top”, “bottom”, “upper”, “lower”, “side”, “left”, “right”, “front”, “rear”, and “within”, when present, are used merely to distinguish one component (or part of a component or state of a component) from another. This list of terms is not exclusive. Such terms are not meant to denote a preference or a particular orientation, and they are not meant to limit embodiments of mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore. In the following detailed description of the example embodiments, numerous specific details are set forth in order to provide a more thorough understanding of the invention. However, it will be apparent to one of ordinary skill in the art that the invention may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0048] FIG. 1 shows a block diagram of a system 100 for mitigating a leak from a hole 131 in a substantially vertical section of a tubing string 140 within a subterranean wellbore 110 according to certain example embodiments. The example system 100 of FIG. 1 includes a subterranean wellbore 110 positioned within a subterranean formation 120, a Xmas tree 195 positioned at an entry point above the subterranean wellbore 110, wellbore circulation equipment 150, temperature control equipment 130, pressure control equipment 135, one or more sealing material receptacles 185, one or more chemical additive receptacles 183, one or more controllers 104, one or more sensor devices 160, one or more users 151 (including one or more optional user systems 155), and a network manager 180. The Xmas tree 195, the wellbore circulation equipment 150, the temperature control equipment 130, and the pressure control equipment 135 may be located at or near the surface 108 (at least for land-based projects).

[0049] The components shown in FIG. 1 are not exhaustive, and in some embodiments, one or more of the components shown in FIG. 1 may not be included in the example system 100. For example, the system 100 may include one or more power sources (e.g., a generator, a battery). Any component of the system 100 may be discrete or combined with one or more other components of the system 100. Also, one or more components of the system 100 may have different configurations. For example, a controller 104 may be included with the temperature control equipment 130. As another example, one or more of the sensor devices 160 may be disposed within or disposed on other components (e.g., a string component 145, a valve of the Xmas tree 195, a port of the Xmas tree 195) of the system 100. As another example, a controller 104, rather than being a stand-alone device, may be part of one or more other components (e.g., part of the pressure control equipment 135, part of a sensor device 160) of the system 100.

[0050] The surface 108 may be ground level for an onshore application and the sea floor / lakebed for an offshore application. For offshore applications, at least some of the field equipment may be located on a platform that sits above the water level. The point where the wellbore 110 begins at the surface 108 may be called the entry point and have the Xmas tree 195 (e.g., an assembly of pipes, valves, and / or other equipment) positioned thereon. While not shown in FIG. 1, there may be multiple wellbores 110, each with its own Xmas tree but that is located close to the other wellheads, drilled into the subterranean formation 120. In such a case, the multiple wellbores 110 may be drilled at the same pad or at different pads.

[0051] The subterranean formation 120 may include one or more of a number of formation types, including but not limited to shale, limestone, sandstone, clay, sand, and salt. In certain embodiments, a subterranean formation 120 may include one or more reservoirs in which one or more resources (e.g., oil, natural gas, water, steam) may be located. One or more of a number of field operations (e.g., fracturing, coring, tripping, drilling, setting casing, production) may be performed to reach an objective of a user 151 with respect to the subterranean formation 120.

[0052] The wellbore 110 may have one or more of a number of segments or hole sections, where each segment or hole section may have one or more of a number of dimensions. Examples of such dimensions may include, but are not limited to, a size (e.g., diameter) of the wellbore 110, a curvature of the wellbore 110, a total vertical depth of the wellbore 110, a measured depth of the wellbore 110, and a horizontal displacement of the wellbore 110. There may be multiple overlapping casing strings of various sizes (e.g., length, outer diameter) contained within and between these segments or hole sections to ensure the integrity of the wellbore construction. At least the beginning of most wellbores 110, as in this example, have one or more of the segments that are substantially vertical. In some cases, one or more of the segments of the subterranean wellbore 110 may additionally have a substantially horizontal section.

[0053] The wellbore 110 in the subterranean formation 120 includes a casing string 125 (sometimes more simply called a casing herein) that substantially abuts against the subterranean formation 120. Specifically, once the wellbore 110 is drilled, the casing string 125 is inserted into the wellbore 110 to stabilize the wellbore 110 and allow for the extraction of subterranean resources (e.g., natural gas, oil) from the subterranean formation 120. The casing string 125 includes a number of casing pipes that are coupled to each other end-to-end to form the casing string 125. In this case, each end of a casing pipe has mating threads (a type of coupling feature) disposed thereon, allowing a casing pipe to be directly or indirectly mechanically coupled to another casing pipe in an end-to-end configuration. The casing pipes of the casing string 125 may be indirectly mechanically coupled to each other using a coupling device, such as a coupling sleeve.

[0054] Each casing pipe of the casing string 125 may have a length and a width (e.g., outer diameter). The length of a casing pipe may vary. For example, a common length of a casing pipe is approximately 40 feet. The length of a casing pipe may be longer (e.g., 60 feet) or shorter (e.g., 10 feet) than 40 feet. The width of a casing pipe may also vary and may depend on the cross-sectional shape of the casing pipe. For example, when the shape of the casing pipe is cylindrical, the width may refer to an outer diameter, an inner diameter, or some other form of measurement of the casing pipe. Examples of a width in terms of an outer diameter may include, but are not limited to, 4-½ inches, 7 inches, 7-⅝ inches, 8 -⅝ inches, 10-¾ inches, 13-⅜ inches, and 14 inches.

[0055] The size (e.g., width, length) of the casing string 125 may be based on the information (e.g., diameter of the borehole drilled) gathered using field equipment with respect to the subterranean wellbore 110. The walls of the casing string 125 have an inner surface that forms a cavity that traverses the length of the casing string 125. Each casing pipe may be made of one or more of a number of suitable materials, including but not limited to steel. Cement is poured into the wellbore 110, often through the cavity of the casing string and then forced upward between the outer surface of the casing string 125 and the wall of the subterranean wellbore 110. In some cases, a liner may additionally be used with, or alternatively be used in place of, some or all of the casing pipes.

[0056] The subterranean wellbore 110 also includes a tubing string 140. The tubing string 140 is made up of a number (e.g., hundreds, thousands) of tubing string components 145, examples of which may include but are not limited to tubing pipes, SPMs, valve subs, and ROGLVs. In this example, there are X components 145 (component 145-1 through component 145-X) of the tubing string 140. The tubing string 140 may be positioned inside the casing sting 125. The components 145 of the tubing string 140 are mechanically coupled to each other end-to-end, usually using mating threads (a type of coupling feature). The components 145 of the tubing string 140 may be mechanically coupled to each other directly or indirectly using a coupling device, such as a coupling sleeve.

[0057] Each component 145 of the tubing string 140 may have a length and a width (e.g., outer diameter). The length of a component 145 of the tubing string 140 may vary. For example, a common length of a component 145 in the form of a tubing pipe is approximately 30 feet. The length of a component 145 in the form of a tubing pipe may be longer (e.g., 40 feet) or shorter (e.g., 10 feet) than 30 feet. Also, the length of a component 145 of the tubing string 140 may be the same as, or different than, the length of an adjacent casing pipe of the casing string 125. The width of a component 145 of the tubing string 140 may also vary and may depend on one or more of a number of factors, including but not limited to the target depth of the wellbore 110, the configuration of a component 145, the total length of the wellbore 110, the inner diameter of the adjacent casing string 125, and the curvature of the wellbore 110. For example, a component 145 in the form of a SPM has an oblong cross-sectional shape, where a component 145 in the form of a tubing pipe has a circular cross-sectional shape.

[0058] The width of a component 145 of the tubing string 140 may refer to an outer diameter, an inner diameter, and / or some other form of measurement of the component 145. Examples of a width in terms of an outer diameter for a component 145 of the tubing string 140 may include, but are not limited to, 7 inches, 5 inches, and 4 inches. The outer diameter of a component 145 of the tubing string 140 may be less than the inner diameter of the casing string 125, resulting in a gap (also called an annulus 138) between the tubing string 140 and the adjacent casing string 125. The walls of each of the components 145 of the tubing string 140 have an inner surface that forms a cavity that traverses the length of the tubing string 140. Each component 145 of the tubing string 140 may be made of one or more of a number of suitable materials, including but not limited to steel.

[0059] At a depth (e.g., hundreds of feet, thousands of feet) within the wellbore 110 is placed one or more packers 192 that are designed to form a substantially fluidic seal with the tubing string 140 and the casing string 125, which isolates the annulus 138 above the packer 192 and the annulus below the packer 192 from each other. This isolation helps with production of a subterranean resource from the target zone of the wellbore 110, which is located downhole from the packer 192 and is now shown in FIG. 1.

[0060] Over time during a field operation (e.g., a production operation), each component 145 of the tubing string 140 may develop one or more holes 131 in one or more of its walls. Each such hole 131 may be the source of a leak, which results in a lower pressure within the cavity of the tubing string 140, which in turn results is a reduced ability to produce the subterranean resource up the tubing string 140, as discussed above. For example, in this case, component 145-1 has developed a hole 131-1, component 145-2 has developed a hole 131-2, component 145-3 has developed a hole 131-3, and component 145-X has developed a hole 131-Y. At a point in time, the number of holes 131 in the tubing string 140 may be the same as, or different than, the number of components 145 of the tubing string 140. In most cases, the number of holes 131 in the tubing string 140 is substantially less than the number of components 145 of the tubing string 140.

[0061] The Xmas tree 195 (also sometimes called a Christmas tree or a tree) of the system 100 is an assembly of valves (e.g., a crown valve, a choke valve), pipes, ports, spools, fittings, and other components to regulate the flow of fluids (e.g., circulation fluid, production fluid) into and / or out of the wellbore 110. The arrangement of components may have any of a number of configurations (e.g., a vertical tree, a horizontal tree). Each valve and / or any other operable component of the Xmas tree 195 may be controlled by a controller 104, by a user 151 (including an associated user system 155), and / or automatically (e.g., using its own controller). Control of each valve and / or any other operable component of the Xmas tree 195 may be based on measurements made by one or more of the sensor devices 160.

[0062] The wellbore circulation equipment 150 may include one or more of a number of components that are used to extract subterranean resources. For example, during production operations, the wellbore circulation equipment 150 may be configured to inject a pressurized fluid (e.g., a liquid, a compressed gas) down the annulus 138. When this is done continuously over a period of time, and if there are no or few holes 131 in the components 145 of the tubing string 140, the fluid returns up the cavity of the tubing string 140 with the subterranean resource. Examples of such components of the wellbore circulation equipment 150 may include, but are not limited to, a compressor, a valve, a pump, piping 189, and a motor. Some or all of the wellbore circulation equipment 150 may operate in series and / or in parallel with each other. Some or all of the wellbore circulation equipment 150 may be controlled by a user 151 (e.g., a production operator), by a controller 104 external to the system 100, by its own controller (e.g., similar to a controller 104), and / or by a controller 104 of the system 100. Operation of some or all of the wellbore circulation equipment 150 may be controlled using measurements made by one or more of the sensor devices 160.

[0063] The temperature control equipment 130 of the system 100 is configured to control the temperature of a fluid that is injected into and / or extracted from the wellbore 110. The temperature control equipment 130 may include one or more of any number of components. Such components may include, but are not limited to, a heater, a heat exchanger, a chiller, a dehumidifier, a humidifier, a valve, piping 189, a controller 104, and a sensor device 160. Some or all of the temperature control equipment 130 may be controlled by a user 151 (e.g., a production operator), by a controller 104 external to the system 100, by its own controller (e.g., similar to a controller 104), and / or by a controller 104 of the system 100. Operation of some or all of the temperature control equipment 130 may be controlled using measurements made by one or more of the sensor devices 160.

[0064] The pressure control equipment 135 of the system 100 is configured to control the pressure of a fluid that is injected into and / or extracted from the wellbore 110. In addition, or in the alternative, the pressure control equipment 135 may be configured to control the pressure within the wellbore 110 (e.g., within the annulus 138 above the packer 192, within the cavity of the tubing string 140). The pressure control equipment 135 may include one or more of any number of components. Such components may include, but are not limited to, a compressor, a regulator, a valve, piping 189, a controller 104, and a sensor device 160. Some or all of the pressure control equipment 135 may be controlled by a user 151 (e.g., a production operator), by a controller 104 external to the system 100, by its own controller (e.g., similar to a controller 104), and / or by a controller 104 of the system 100. Operation of some or all of the pressure control equipment 135 may be controlled using measurements made by one or more of the sensor devices 160.

[0065] Each of the one or more chemical additive receptacles 183 of the system 100 is configured to contain one or more of a number of chemical additives 184. Such chemical additives 184 may be used to disintegrate (e.g., dissolve, break apart) some or all of the sealing material 188 that is located in the wellbore 110. For example, if a user 151 wants to uncover one or more of the holes 131 in one or more of the components 145 of the tubing string 140, a chemical additive 184 having chemical properties known to disintegrate (e.g., dissolve, break apart) some or all of the sealing material 188 when that sealing material 188 is exposed to the chemical additive 184 may be added to a fluid injected into the annulus 138 and / or the cavity of the tubing string 140. A chemical additive receptacle 183 may have any form (e.g., a tank, a bucket, a sealed container) and be made of any of a number of suitable materials (e.g., plastic, glass, steel) that do not appreciably react with the chemical additive 184 over time.

[0066] Examples of a chemical additive 184 may include, but are not limited to, sodium hydroxide, potassium hydroxide, magnesium hydroxide, potassium hydroxide, baking soda, a strong caustic, and acid. A chemical additive 184 may be removed from a chemical additive receptacle 183 and / or added to a fluid injected into the wellbore 110 using piping 189 (or some other form of conveyance) and / or by hand (e.g., manually by a user 151). Handling of some or all of a chemical additive 184 may be performed by a user 151 (e.g., a production operator), by a controller 104 external to the system 100, by a controller of the chemical additive receptacle 183 (e.g., similar to a controller 104), and / or by a controller 104 of the system 100. Handling of some or all of a chemical additive 184 may be controlled using measurements made by one or more of the sensor devices 160. A chemical additive, when introduced into the wellbore 110, may be configured to have no or substantially no adverse effects on any of the equipment (e.g., the components 145 of the tubing string 140, the casing string 125, the packer 192) in the wellbore 110 outside of a sealing material 188.

[0067] Each of the one or more sealing material receptacles 185 of the system 100 is configured to contain some or all of the various sealing material 188 that is used to cover one or more of the holes 131 in the components 145 of the tubing string 140 according to certain example embodiments. Each sealing material receptacle 185 may have any form (e.g., a tank, a bucket, a box, a sealed container) and be made of any of a number of suitable materials (e.g., plastic, glass, steel, wood, cardboard) that do not appreciably react with and / or otherwise alter the properties of a sealing material 188 over time.

[0068] Each sealing material 188 is configured to completely or substantially cover a hole 131 in a component 145 of the tubing string 140 while the tubing string 140 is in situ within the wellbore 110. As discussed below, when the sealing material 188 is introduced from above an entry point of the subterranean wellbore 110 into the cavity of the tubing string 140 or the annulus 138 (depending on the configuration of the production operation), the sealing material 188 is drawn to a hole 131 by a differential in pressure between the annulus 138 and the cavity of the tubing string 140 as the sealing material 188 falls toward the bottom of the wellbore 110. In this way, the sealing material 188 does not have a high density and / or mass to prevent the velocity of the sealing material 188 falling in the cavity of the tubing string 140 to overpower the force of the differential pressure at the hole 131.

[0069] In some cases, the sealing material 188 is malleable and / or flexible, allowing the sealing material 188 to change its shape based on pressure and / or some other factor in order to provide a more complete seal over a hole 131. In addition, or in the alternative, the sealing material 188 may be increased and / or decreased in size (e.g., by hand, using scissors) before the sealing material 188 is introduced into the wellbore 110. A sealing material 188 may be or include a flexible mass (e.g., similar to a putty) and / or string-like features.

[0070] In certain example embodiments, a sealing material 188 naturally decomposes after being exposed to the environment within the cavity inside the tubing string 140 for some period of time (e.g., a few weeks, a month, two months). In addition, or in the alternative, a sealing material 188 may disintegrate (e.g., dissolve, break apart) when exposed to a pressure that exceeds a threshold pressure value (e.g., 300 psi) and / or a temperature that exceeds a threshold temperature value (e.g., 200° F.). In addition, or in the alternative, a sealing material 188 may disintegrate (e.g., dissolve, break apart) when the sealing material 188 is exposed to a chemical additive 184.

[0071] When multiple sealing materials 188 are used to cover holes 131 in one or more components 145 of the tubing string 140, one sealing material 188 may have one or more different characteristics compared to one or more of the other sealing materials 188. In such a case, one sealing material 188 may have a temperature threshold value, a pressure threshold value, a chemical composition, and / or a natural disintegration period that differs from the temperature threshold value, the pressure threshold value, the chemical composition, and / or the natural disintegration period of one or more of the other sealing materials 188. In this way, a targeted approach may be made to affirmatively uncover certain holes 131 using pressure, temperature, and / or chemical additives without uncovering all of the holes 131 at a point in time.

[0072] In some cases, a sealing material 188 is designed to behave differently in different situations or stages. For example, a sealing material 188 may be designed to flatten against the wall of a component 145 around a hole 131 once the sealing material 188 covers the hole 131. In this way, the sealing material 188 may be configured to provide a better chance for a complete or substantially complete seal around the hole 131 rather than merely covering the hole 131.

[0073] Each sensor device 160 of the system 100 includes one or more sensors that measure one or more parameters (e.g., pressure, flow rate, temperature, humidity, location, content of a fluid, voltage, electrical current, etc.). Examples of a sensor of a sensor device 160 may include, but are not limited to, a temperature sensor, a flow sensor, a pressure sensor, a gas spectrometer, a voltmeter, an ammeter, a gyroscope, a spectrograph, a gas chromatograph, and a camera. A sensor device 160 may be a stand-alone device or integrated with another component of the system 100.

[0074] As discussed above, a parameter measured by a sensor device 160 may be associated with a pressure (e.g., a pressure in the annulus 138, a pressure within the cavity of the tubing string 140, a differential pressure between the annulus 138 and the cavity of the tubing string 140) in the wellbore 110. In some cases, in addition, a parameter measured by a sensor device 160 may be associated with one or more other components (e.g., a motor, a power source, a valve position) of the system 100. For example, a sensor device 160 may be configured to determine the degree to which a valve within the system 100 is open or closed. In some cases, a sensor device 160 may additionally or alternatively measure a parameter outside of the system 100. For example, a sensor device 160 may be configured to measure a parameter associated with a power supply, the ambient environment, and / or some other part of the system 100 not shown in FIG. 1.

[0075] In some cases, a number of sensor devices 160, each measuring a different parameter, may be used in combination to determine and confirm whether a controller 104 should take a particular action (e.g., operate a valve, adjust the speed of a motor, operate or adjust the operation of the wellbore circulation equipment 150, operate or adjust the operation of the temperature control equipment 130). A sensor device 160 may operate continuously, randomly, periodically (e.g., every 30 seconds, every minute, every hour), or discretely. A sensor device 160 may operate at the direction of a controller 104, at the direction of a user 151, and / or autonomously (e.g., with its own controller). When a sensor device 160 includes its own controller (or portions thereof), similar to a controller 104, then the sensor device 160 may be considered a type of computer device, as discussed below with respect to FIG. 20.

[0076] A user 151 may be any person that interacts, directly or indirectly, with a controller 104 and / or any other component of the system 100. Examples of a user 151 may include, but are not limited to, a business owner, an engineer, a company representative, a chemist, a geologist, a consultant, a contractor, an end user, and a manufacturer's representative. A user 151 may use one or more user systems 155, which may include a display (e.g., a GUI). A user system 155 of a user 151 may interact with (e.g., send data to, obtain data from) a controller 104 via an application interface and using the communication links 105. The user 151 may also interact directly with a controller 104 through a user interface (e.g., keyboard, mouse, touchscreen). Examples of a user system 155 may include, but are not limited to, a cell phone, a smart phone, a desktop computer, a laptop computer, a tablet, and a handheld electronic device. A user system 155 may be considered a type of computer device, as discussed below with respect to FIG. 20.

[0077] The network manager 180 is a device or component that controls all or a portion (e.g., a communication network, a controller 104) of the system 100 or portions thereof. The network manager 180 may be substantially similar to some or all of a controller 104. For example, the network manager 180 may include a controller that has one or more components and / or similar functionality to some or all of a controller 104. Alternatively, the network manager 180 may include one or more of a number of features in addition to, or altered from, the features of a controller 104. As described herein, control and / or communication with the network manager 180 may include communicating with one or more other components of the sample collection system 100 (including one or more components thereof) and / or another system. In such a case, the network manager 180 may facilitate such control and / or communication. The network manager 180 may be called by other names, including but not limited to a master controller, a network controller, and an enterprise manager. The network manager 180 may be considered a type of computer device, as discussed below with respect to FIG. 20.

[0078] Interaction between each controller 104, the sensor devices 160, the users 151 (including any associated user systems 155), the network manager 180, the wellbore circulation equipment 150, the temperature control equipment 130, the pressure control equipment 135, and other components of the system 100 may be conducted using communication links 105 and / or power transfer links 187. Each communication link 105 may include wired (e.g., Class 1 electrical cables, electrical connectors, Power Line Carrier, RS485) and / or wireless (e.g., sound or pressure waves in a fluid in the annulus 138, Wi-Fi, Zigbee, visible light communication, cellular networking, Bluetooth, Bluetooth Low Energy (BLE), ultrawide band (UWB), WirelessHART, ISA100) technology.

[0079] Each power transfer link 187 may include one or more electrical conductors, which may be individual or part of one or more electrical cables. In some cases, as with inductive power, power may be transferred wirelessly using power transfer links 187. A power transfer link 187 may transmit power from one component of the system 100 to another component of the system 100. Each power transfer link 187 may be sized (e.g., 12 gauge, 18 gauge, 4 gauge) in a manner suitable for the amount (e.g., 480V, 24V, 120V) and type (e.g., alternating current, direct current) of power transferred therethrough.

[0080] A controller 104 of the system 100 is configured to communicate with and in some cases control one or more of the other components (e.g., a sensor device 160, a motor, the wellbore circulation equipment 150, the temperature control equipment 130, the pressure control equipment 135,, a valve, another controller 104) of the system 100. A controller 104 may perform any of a number of functions that include, but are not limited to, obtaining and sending data, evaluating data, following protocols, running algorithms, and sending commands.

[0081] A controller 104 may include one or more of a number of components. For example, such components of a controller 104 may include, but are not limited to, a control engine, a communication module, a timer, a power module, a storage repository, a hardware processor, a memory, a transceiver, an application interface, and a security module. A controller 104 (or components thereof) may be located at or near the various components of the system 100. In addition, or in the alternative, a controller 104 (or components thereof) may be located remotely from (e.g., in the cloud, at an office building) the various components of the system 100.

[0082] When there are multiple controllers 104 (e.g., one controller 104 for some or all of the wellbore circulation equipment 150, another controller 104 for some or all of the temperature control equipment 130, yet another controller 104 for the pressure control equipment 135), each controller 104 may operate independently of each other. Alternatively, two or more of the multiple controllers 104 may work cooperatively with each other. As yet another alternative, one of the controllers 104 may control some or all of one or more other controllers 104 in the system 100 or portion thereof. Each controller 104 may be considered a type of computer device, as discussed below with respect to FIG. 20.

[0083] FIGS. 2 through 17 shows examples of how example embodiments may be used with part of a wellbore 210 over time according to certain example embodiments. Specifically, FIGS. 2 through 17 show the use of example embodiments with annular gas lift (inject tubing / produce annulus). FIGS. 21 through 24 below show the use of example embodiments with conventional gas lift (inject annulus / produce tubing) operations. Referring to the description above with respect to FIG. 1, FIG. 2 shows a sectional view of part of a wellbore 210 with which example embodiments may be used. The part of the wellbore 210 shown in FIG. 2 includes part of a casing string 225 that borders the wellbore 210 with a subterranean formation 220. Positioned inside the casing string 225 is part of a tubing string 240 that includes four components 245 (component 245-1, component 245-2, component 245-3, and component 245-4). Each of the components 245 of the wellbore 210 of FIG. 2 may be substantially the same as the corresponding components of the system 100 of FIG. 1 above. At the point in time captured in FIG. 2, none of the four components 245 has a hole (e.g., hole 131) in its walls. Under these circumstances, as a fluid 233 (e.g., a liquid, a pressurized gas) is pumped down the cavity 239 of the tubing string 240 (e.g., by the wellbore circulation equipment 150, by the pressure control equipment 135) at a pressure P1, a produced fluid 234 (which includes a subterranean resource) travels up the annulus 238 at a pressure P2 for extraction from the wellbore 210.

[0084] Over time, one or more of the components 245 of the tubing string 240 develop a hole (e.g., hole 131). FIG. 3 shows a sectional view of the part of the wellbore 210 of FIG. 2 at a subsequent time when a hole 331 has developed in one of the tubing string components 245 according to certain example embodiments. Specifically, component 245-2 (e.g., a tubing string pipe, a SPM) has a hole 331 in its wall. As a result of the hole 331, the pressure P3 in the cavity 239 of the tubing string 240 has decreased from the pressure P1 of FIG. 2. Consequently, as the fluid 233 is pumped down the cavity 239 of the tubing string 240 at a pressure P3, little if any of the produced fluid 234 travels up the annulus 238 for extraction from the wellbore 210 because of the low pressure P3 in the cavity 239 of the tubing string 240. In other words, production is greatly reduced or stopped as a result of the hole 331 in the component 245-2 of the tubing string 240. In the current art, either the wellbore 210 would be abandoned or the tubing string 240 would be pulled out of the wellbore 210 to replace the component 245-2. The former option results in lost production opportunity, and the latter option results in down time and high costs. The down time of the latter option may be extended if a rig required to trip out and back in the wellbore 210 is not on site and available. Use of example embodiments provides a solution to the situation presented in FIG. 3 that completely or substantially restores production with negligible down time, no need for a rig and related equipment, and minimal cost of implementation.

[0085] FIG. 4 shows a sectional view of the part of the wellbore 210 of FIG. 3 at a subsequent time when an attempt to cover the hole 331 is being made according to certain example embodiments. Specifically, one or more (in this case, three) pieces of sealing material 488 (sealing material 488-1, sealing material 488-2, and sealing material 488-3) may be introduced (e.g., dropped) into the cavity 239 of the tubing string 240. For example, a crown valve of the Xmas tree (e.g., Xmas tree 195) may be opened (provided that there is a sufficient isolation valve), and the sealing material 488 may be introduced into (e.g., dropped down) the cavity 239 (or, in alternative embodiments, into the annulus 238). As another example, a specialized injection device rated for pressure and incorporated into the wellbore circulation equipment (e.g., wellbore circulation equipment 150) may be used to introduce the sealing material 488 into the cavity 239 (or, in alternative embodiments, into the annulus 238). At the time captured in FIG. 4, the pressure P3 within the cavity 239 of the tubing string 240 (maintained by continuing to inject the fluid 233 into the cavity 239 of the tubing string 240) is less than the pressure P2 within the annulus 238.

[0086] In some cases, a procedure may be followed in an effort to slow the descent of the sealing materials 488 within the cavity 239 in the tubing string 240. For example, one procedure may be to stop injecting pressurized gas into the wellbore 210 when the sealing materials 488 are introduced into the cavity 239. Once the sealing materials 488 are in the cavity 239, a gas may be injected at a low pressure and a low flow rate until the hole 331 is at least substantially covered by one of the sealing materials 488. Once the hole 331 is covered by the sealing material 488-2, a sensor device (e.g., sensor device 160) measures an increase in pressure as an indication that the hole 331 is, in fact, covered. At that time, the gas pressure may be increased to help secure the sealing material 488-2 to the hole 331.

[0087] As another example, with the wellbore 210 temporarily taken out of service, any gas lift is stopped, and the pressure in the cavity 239 of the tubing string 240 is bled down. Then, the pressure P3 within the cavity 239 may be increased (e.g., to 1000 psi) using gas lift gas. Then, once the sealing materials 488 are introduced (e.g., dropped) into the cavity 239, a gas lift injection (e.g., at 500 mcfpd) down the cavity 239 may commence while also rapidly bleeding down the pressure P2 within the annulus 238 and opening the flowline. This environment encourages a sealing material 488 to cover the hole 331.

[0088] As yet another example, oil, water, and / or condensate may be pumped down the cavity 239 of the tubing string 240. At some point, the pumping is stopped, and the sealing materials 488 are introduced into the cavity 239. The oil, water, and / or condensate slow the velocity of the sealing materials 488. Then, a gas lift injection (e.g., at 500 mcfpd) down the cavity 239 may commence to help encourage one of the sealing materials 488 to cover the hole 331. In some cases, one or more other liquids may additionally or alternatively be used to control the velocity of the sealing material 488 and better place the sealing material 488 relative to the hole 331.

[0089] In certain example embodiments, a controller (e.g., controller 104) and / or a user (e.g., user 151) may be used to determine one or more of a number of factors for implementing example embodiments. Examples of such factors may include, but are not limited to, what type of sealing material 488 to use, how much sealing material 488 to introduce into the wellbore 110, the optimal size or range of sizes of the sealing material 488, the target flow rate, pressure, and / or temperature of the fluid 233 injected into the wellbore 110, the content (e.g., water, condensate, gas, liquid) of the fluid 233 injected into the wellbore 110, and the concentration and / or amount of each content element of the fluid 233, A controller and / or a user may balance or optimize these factors in light of gravity, drag, and / or suction force in an effort to ensure that the suction force through the hole 331 is sufficient to overcome the inertia of the sealing material 488 and allow the sealing material 488 to cover the hole 331 without being dislodged.

[0090] FIG. 5 shows a sectional view of the part of the wellbore 210 of FIG. 4 at a subsequent time when the hole 331 becomes covered according to certain example embodiments. Specifically, as sealing material 488-2 falls due to gravity and the flow of the fluid 233 within the cavity 239 of the tubing string 240, the force applied through the hole 331 bv the differential between the pressure P2 within the annulus 238 and the pressure P3 within the cavity 239 of the tubing string 240 (maintained by continuing to inject the fluid 233 into the cavity 239 of the tubing string 240). As a result, sealing material 488-2 is sucked against the wall of the component 245-2 of the tubing string 240, thereby covering or substantially covering the hole 331. Sealing material 488-1 and sealing material 488-3 continue their gravity-assisted and fluid-assisted (from the fluid 233) descent through the cavity 239 of the tubing string 240 toward the bottom of the wellbore 210. When sealing material 448-2 covers the hole 331, the pressure P1 returns to the cavity 239 of the tubing string 240.

[0091] FIG. 6 shows a sectional view of the part of the wellbore 210 of FIG. 5 at a subsequent time when the hole 331 remains covered during production operations according to certain example embodiments. Specifically, once the hole 331 is covered by the sealing material 488-2, the pressure P1 within the cavity 239 of the tubing string 230 returns to what it was at the time captured in FIG. 2 before the hole 331 emerged. As a result, by continuing to inject the fluid 233 into the cavity 239 of the tubing string 240, the produced fluid 234 traveling up the annulus 238 is able to reach the surface (e.g., surface 108) because of the elevated pressure P1 and improved flow rate in the annulus 238.

[0092] FIG. 7 shows a sectional view of the part of the wellbore 210 of FIG. 6 at a subsequent time when the process of using pressure to disintegrate the sealing material 488-2 covering the hole 331 begins according to certain example embodiments. As discussed above, in certain example embodiments, the sealing material 488-2 may be designed to disintegrate when the pressure within the cavity 239 of the tubing string 240 reaches a threshold pressure value. The pressure may be increased directly in the cavity 239 of the tubing string 240 (as shown in FIG. 7 where the pressure of the cavity 239 is increased to P4). In addition, or in the alternative, the sealing material 488-2 may disintegrate when the differential pressure (e.g., pressure P4 in the cavity 239 of the tubing string 240 relative to pressure P2 in the annulus 238 in this case) reaches a threshold value. In this way, controlling pressure within the cavity 239 and / or the annulus 238 may be used to disintegrate the sealing material 488-2.

[0093] As an alternative, rather than disintegrating the sealing material 488-2 within the wellbore due to an elevated amount of direct pressure or differential pressure, the sealing material 488-2 may be dislodged from the hole 331 using an elevated amount of direct pressure and / or due to an elevated differential pressure. For example, referring to FIG. 7, the pressure P4 in the cavity 239 of the tubing string 240 may be significantly lower than pressure P1 from FIG. 3 and lower than the pressure P2 in the annulus 238. In such a case, the relatively higher pressure P2 in the annulus 238 relative to the pressure P4 in the cavity 239 (e.g., stop injecting down the cavity 239 of the tubing string 240 and inject down the anulus 238) may dislodge the sealing material 488-2 from the hole 331.

[0094] FIG. 8 shows a sectional view of the part of the wellbore 210 of FIG. 7 at a subsequent time when the sealing material 488-2 has disintegrated using pressure according to certain example embodiments. Specifically, once the pressure P4 in the cavity 239 of the tubing string 240 (or the differential between pressure P4 in the cavity 239 and P2 in the annulus 238) reaches the threshold pressure value (based, for example, on the properties of the sealing material 488-2), the sealing material 488-2 disintegrates. When this occurs, as shown in FIG. 8, the hole 331 in the component 245-2 of the tubing string 240 is uncovered, the pressure P3 in the cavity 239 of the tubing string 240 drops, and the flow rate of the produced fluid 234 up the annulus 238 is greatly reduced or stopped, similar to what is shown in FIG. 3 above.

[0095] FIG. 9 shows a sectional view of the part of the wellbore 210 of FIG. 6 at a subsequent time when the process of using a chemical additive 984 to disintegrate the sealing material covering the hole begins according to certain example embodiments. As discussed above, in certain example embodiments, the sealing material 488-2 may be designed to disintegrate when the sealing material 488-2 interacts with a particular chemical additive 984 (e.g., similar to the chemical additive 184 discussed above). The chemical additive 984 may be added directly to the cavity 239 of the tubing string 240 and / or indirectly by mixing the chemical additive 984 with the fluid 233 injected into the cavity 239 of the tubing string 240, as shown in FIG. 9.

[0096] FIG. 10 shows a sectional view of the part of the wellbore 210 of FIG. 9 at a subsequent time when the process of using a chemical additive 984 to disintegrate the sealing material 488-2 covering the hole 331 continues according to certain example embodiments. For example, as enough of the mixture of the fluid 233 and the chemical additive 984 is injected into the cavity 239 of the tubing string 240, the chemical additive 984 mixes in with the produced fluid 234 that flows up the annulus 238. As another example, the mixture of the fluid 233 and the chemical additive 984 may be pumped down the annulus 238 so that the chemcial additive 984 reaches the sealing material 488-2 with relatively less dilution.

[0097] FIG. 11 shows a sectional view of the part of the wellbore 210 of FIG. 10 at a subsequent time when the sealing material 488-2 has disintegrated using the chemical additive 984 according to certain example embodiments. When a threshold volume of the chemical additive 984 interacts with the sealing material 488-2 in the cavity 239, the sealing material 488-2 disintegrates. When this occurs, as shown in FIG. 11, the hole 331 in the component 245-2 of the tubing string 240 is uncovered, the pressure P3 in the cavity 239 of the tubing string 240 drops, and the flow rate of the produced fluid 234 up the annulus 238 is greatly reduced or stopped, similar to what is shown in FIG. 3 above.

[0098] FIG. 12 shows a sectional view of the part of the wellbore 210 of FIG. 6 at a subsequent time when the process of using temperature to disintegrate the sealing material 488-2 covering the hole 331 begins according to certain example embodiments. As discussed above, in certain example embodiments, the sealing material 488-2 may be designed to disintegrate when the temperature within the cavity 239 of the tubing string 240 reaches a threshold temperature value. At the time captured in FIG. 12, the temperature T1 in the cavity 239 of the tubing string 240 is below the threshold temperature value at which the sealing material 488-2 is configured to dissolve.

[0099] FIG. 13 shows a sectional view of the part of the wellbore 210 of FIG. 12 at a subsequent time when the sealing material 488-2 has disintegrated using temperature according to certain example embodiments. In FIG. 13, the temperature of the cavity 239 is increased to T2 from T1, where T2 is at or above the threshold temperature value at which the sealing material 488-2 is configured to dissolve. The temperature in the cavity 239 may be increased directly (e.g., by introducing a heated fluid down the cavity 239 of the tubing string 240 or indirectly by increasing the temperature in the annulus 238, which eventually partially transfers (e.g., through the thermally conductive material of the component 245-2) to the sealing material 488-2. When this occurs, as shown in FIG. 13, the hole 331 in the component 245-2 of the tubing string 240 is uncovered, the pressure P3 in the cavity 239 of the tubing string 240 drops, and the flow rate of the produced fluid 234 up the annulus 238 is greatly reduced or stopped, similar to what is shown in FIG. 3 above.

[0100] FIG. 14 shows a sectional view of the part of the wellbore 210 of FIG. 6 at a subsequent time when a hole 1431 has developed in another of the tubing string components 245-3 according to certain example embodiments. Specifically, while the hole 331 in component 245-2 remains covered by sealing material 488-2, a hole 1431 has appeared in the wall of component 245-3. As a result of the hole 1431 in component 245-3 of the tubing string 240, the pressure P5 in the cavity 239 of the tubing string 240 has decreased from the pressure P1 of FIG. 2. Consequently, as the fluid 233 is pumped down the cavity 239 of the tubing string 240 at a pressure P1, little if any of the produced fluid 234 travels up the annulus 238 for extraction from the wellbore 210 due to the low pressure P5 in the cavity 239 of the tubing string 240. In other words, production is greatly reduced or stopped as a result of the hole 1431 in the component 245-3 of the tubing string 240.

[0101] To bring production back up, a similar process discussed above with respect to FIGS. 4 through 6 may be followed. Specifically, FIG. 15 shows a sectional view of the part of the wellbore 210 of FIG. 14 at a subsequent time when an attempt to cover the additional hole 1431 is being made according to certain example embodiments. At the time captured in FIG. 15, one or more (in this case, three) pieces of sealing material 1588 (sealing material 1588-1, sealing material 1588-2, and sealing material 1588-3) may be introduced (e.g., dropped) into the cavity 239 of the tubing string 240. At the time captured in FIG. 15, the pressure P5 within the cavity 239 of the tubing string 240 (even with continuing to inject the fluid 233 into the cavity 239) is less than the pressure P2 within the annulus 238.

[0102] FIG. 16 shows a sectional view of the part of the wellbore 210 of FIG. 15 at a subsequent time when the additional hole 1431 becomes covered according to certain example embodiments. Specifically, as sealing material 1588-1 falls due to gravity within the cavity of the tubing string 240, the force applied through the hole 331 bv the differential between the pressure P2 within the annulus 238 and the pressure P5 within the cavity 239 of the tubing string 240. As a result, sealing material 1588-1 is sucked against the wall of the component 245-3 of the tubing string 240, thereby covering or substantially covering the hole 1431. Sealing material 1588-2 and sealing material 1588-3 continue their gravity-assisted and / or fluid-assisted (from the flow of the fluid 233) descent through the cavity 239 of the tubing string 240 toward the bottom of the wellbore 210. As a result, the pressure in the annulus 238 returns to P2. During this time, hole 331 in component 245-2 remains covered by sealing material 488-2.

[0103] FIG. 17 shows a sectional view of the part of the wellbore 210 of FIG. 16 at a subsequent time when the original hole 331 becomes uncovered by passage of time according to certain example embodiments. As discussed above, in certain example embodiments, a sealing material (in this case, sealing material 488-2) may be configured to disintegrate after a period of time (e.g., approximately two weeks, approximately one month) has passed. This period of time may be influenced by any of a number of factors, including but not limited to flow rate of the produced fluid 234 that flows past the sealing material 488-2, the size of the hole 331 covered by the sealing material 488-2, the contents of the produced fluid 234, and the amount of force applied to the sealing material 488-2 by the pressure differential in the wellbore 210.

[0104] In this case, the sealing material 488-2 has disintegrated due to the passage of time, and so hole 331 becomes uncovered. As a result, the pressure P3 in the cavity 239 of the tubing string 240 has decreased from the pressure P1 of FIG. 16. Consequently, as the fluid 233 is pumped down the cavity 239 of the tubing string 240, little if any of the produced fluid 234 travels up the annulus 238 for extraction from the wellbore 210. In other words, production is greatly reduced or stopped as a result of the hole 331 in the component 245-2 of the tubing string 240 becoming uncovered. The hole 1431 in the component 245-3 of the tubing string 240 remains covered by sealing material 1588-1. In some cases, a change (e.g., increase) in the flow rate of the fluid 233 may be used as a separate method of attempting to uncover a hole 331 or may be used in conjunction with the manipulation of temperature, the manipulation of pressure, and / or using chemical additives 984 to uncover a hole 331.

[0105] FIG. 18 shows a flowchart 1858 of a method for mitigating a leak from a hole in a substantially vertical section of a string within a subterranean wellbore according to certain example embodiments. While the various steps in this flowchart 1858 are presented sequentially, one of ordinary skill will appreciate that some or all of the steps may be executed in different orders, may be combined or omitted, and some or all of the steps may be executed in parallel. Further, in one or more of the example embodiments, one or more of the steps shown in this example method may be omitted, repeated, and / or performed in a different order.

[0106] In addition, a person of ordinary skill in the art will appreciate that additional steps not shown in FIG. 18 may be included in performing this method. Accordingly, the specific arrangement of steps should not be construed as limiting the scope. Further, a particular computer device, such as a controller 104 or other type of computer device discussed below with respect to FIG. 20, may be used to perform or facilitate performance of one or more of the steps (or portions thereof) for the method shown in FIG. 18 in certain example embodiments. Any of the functions (or portions thereof) performed below by a controller 104 may involve the use of one or more protocols, one or more algorithms, and / or stored data stored in a storage repository. In some cases, one or more of the various steps in the method of FIG. 18 may be performed automatically, as by the controller 104 of the example system 100.

[0107] The method shown in FIG. 18 is merely an example that may be performed by using an example system 100 described herein. In other words, systems for mitigating a leak from a hole 131 in a substantially vertical section of a string 140 within a subterranean wellbore 110 may perform other functions using other methods in addition to and / or aside from those shown in FIG. 18. Referring to the description above with respect to FIGS. 1 through 17, the method shown in the flowchart 1858 of FIG. 18 begins at the START step and proceeds to step 1861, where an indication of a leak in a tubing string 140 in a vertical section of a wellbore 110 is obtained. The indication may be an output from a model or other type of algorithm. In addition, or in the alternative, the indication may be a measurement of a parameter (e.g., pressure in the wellbore 110) made by one or more sensor devices 160. The vertical section of the wellbore 110 is defined below with respect to FIG. 19. The leak is caused by a hole 131 in one or more walls of one or more components 145 of the tubing string 140. The indication may be obtained by a controller 104, a user 151 (including an associated user system 155), the network manager 180, and / or some other entity associated with the system 100.

[0108] In step 1862, one or more sealing materials 188 are introduced into the cavity (e.g., cavity 239) of the tubing string 140. The sealing materials 188 may be introduced by a user 151 (including an associated user system 155), a controller 104, the network manager, and / or some other entity of the system 100. In some cases, in order to reduce the velocity of the sealing materials 188 falling through the cavity of the tubing string 140, the environment within the cavity of the tubing string 140 may be prepared and / or controlled in some way prior to when the sealing materials 188 are introduced and / or while the sealing materials 188 are falling in the cavity of the tubing string 140 toward the one or more holes 131. The sealing materials 188 may be obtained from one or more sealing material receptacles 185. The sealing materials 188, when falling within the cavity of the tubing string 140, are designed to cover one or more of the holes 131 in one or more components 145 of the tubing string 140.

[0109] In step 1863, a determination is made as to whether the leak remains. In other words, a determination is made as to whether the one or more holes 131 have been covered by the sealing materials 188. The determination may be made by a controller 104, a user 151 (including an associated user system 155), the network manager 180, and / or some other entity associated with the system 100. The determination may be based, in part, on measurements made by one or more sensor devices 160, one or more algorithms, one or more protocols, and / or stored data. If the leak remains, then the process reverts to step 1862. If the leak does not remain, then the process proceeds to step 1864.

[0110] In step 1864, a determination is made as to whether there is another leak. For example, initially there may have been multiple holes 131 to cover, and after step 1863, it is determined that some, but not all, of the holes 131 were covered by the sealing material 188. The determination may be made by a controller 104, a user 151 (including an associated user system 155), the network manager 180, and / or some other entity associated with the system 100. The determination may be based, in part, on measurements made by one or more sensor devices 160, one or more algorithms, one or more protocols, and / or stored data. If there is another leak, then the process reverts to step 1862. If there is not another leak, then the process proceeds to step 1865.

[0111] In step 1865, a determination is made as to whether one or more of the sealing materials 188 is to be affirmatively removed. Step 1865 may occur after the passage of some amount of time (e.g., a day, a week, a month) since the performance of step 1862. The determination may be based, for example, on factors such as production data, availability of a rig, projected longevity of the sealing material 188, effectiveness of the sealing material 188 in covering a hole 131, and an amount of time since the sealing material 188 began covering the hole 131. The determination may be made by a controller 104, a user 151 (including an associated user system 155), the network manager 180, and / or some other entity associated with the system 100. The determination may be based, in part, on measurements made by one or more sensor devices 160, one or more algorithms, one or more protocols, and / or stored data. If one or more of the sealing materials is to be affirmatively removed, then the process proceeds to step 1866. If one or more of the sealing materials 188 is not to be affirmatively removed, then the process proceeds to step 1872.

[0112] In step 1866, a determination is made as to whether pressure is used to disintegrate one or more of the sealing materials 188. The determination may be made by a controller 104, a user 151 (including an associated user system 155), the network manager 180, and / or some other entity associated with the system 100. The determination may be based, in part, on measurements made by one or more sensor devices 160, one or more algorithms, one or more protocols, and / or stored data. If pressure is to be used to disintegrate one or more of the sealing materials 188, then the process proceeds to step 1867. If pressure is not to be used to disintegrate one or more of the sealing materials 188, then the process proceeds to step 1868.

[0113] In step 1867, the pressure control equipment 135 is operated. In other words, some or all of the pressure control equipment 135 is operated in such a way as to increase the pressure within the wellbore 110 (or portion thereof) to exceed the threshold pressure value that disintegrates one or more of the sealing materials 188 that cover one or more of the holes 131 in one or more components 145 of the tubing string 140. Other equipment (e.g., the wellbore circulation equipment 150, the temperature control equipment 130) may also be operated in conjunction with the pressure control equipment 135 in order to achieve a target pressure within the wellbore 110 (or portion thereof). The pressure control equipment 135 may be operated by a controller 104, a user 151 (including an associated user system 155), the network manager 180, and / or some other entity associated with the system 100. When step 1867 is complete, the process proceeds to step 1873.

[0114] In step 1868, a determination is made as to whether temperature is used to disintegrate one or more of the sealing materials 188. The determination may be made by a controller 104, a user 151 (including an associated user system 155), the network manager 180, and / or some other entity associated with the system 100. The determination may be based, in part, on measurements made by one or more sensor devices 160, one or more algorithms, one or more protocols, and / or stored data. If temperature is to be used to disintegrate one or more of the sealing materials 188, then the process proceeds to step 1869. If temperature is not to be used to disintegrate one or more of the sealing materials 188, then the process proceeds to step 1871.

[0115] In step 1867, the temperature control equipment 130 is operated. In other words, some or all of the temperature control equipment 130 is operated in such a way as to increase the temperature within the wellbore 110 (or portion thereof) to exceed the threshold temperature value that disintegrates one or more of the sealing materials 188 that cover one or more of the holes 131 in one or more components 145 of the tubing string 140. Other equipment (e.g., the wellbore circulation equipment 150, the pressure control equipment 135) may also be operated in conjunction with the temperature control equipment 130 in order to achieve a target temperature within the wellbore 110 (or portion thereof). The temperature control equipment 130 may be operated by a controller 104, a user 151 (including an associated user system 155), the network manager 180, and / or some other entity associated with the system 100. When step 1869 is complete, the process proceeds to step 1873.

[0116] In step 1871, one or more chemical additives 184 are introduced into the cavity (e.g., cavity 239) of the tubing string 140. Each chemical additive 184 may be obtained from a chemical additive receptacle 183. A chemical additive 184 may be introduced using piping 189 and / or some other conveyance system to move the chemical additive 184 from the chemical additive receptacle 183 to the wellbore 110. The chemical additives 184 may be introduced by a user 151 (including an associated user system 155), a controller 104, the network manager, and / or some other entity of the system 100. In some cases, chemical additives 184 have little or no effect on any other aspect of the wellbore 110 and its components except for the sealing materials 188 that are covering holes 131 in the components 145 of the tubing string 140. The particular chemical additive 184, including the amount of the particular chemical additive 184, that is introduced may be based on one or more of a number of factors, including but not limited to the volume of the wellbore 110 above the packer 192, the chemical composition of the sealing material 188 that is being targeted, the interaction of the chemical additive 184 with the fluid (e.g., fluid 233) injected into the annulus 138, and the target time to have the sealing material 188 disintegrated.

[0117] In step 1872, a passage of time is allowed for the sealing material 188 to naturally disintegrate. If the sealing material 188 is not configured to naturally disintegrate, then this step 1872 is optional. The passage of time may be exact (e.g., 27 hours) or broad (within five to seven days), depending on one or more factors that may include but are not limited to the chemical composition of the sealing material 188, the chemical composition of the fluids (e.g., fluid 233, produced fluid 234, chemical additives 184) present in the wellbore 110 in the area of the sealing material 188, temperature in the wellbore 110, and pressure in the wellbore 110.

[0118] In step 1873, a determination is made as to whether the tubing string 140 is ready to be pulled out. The tubing string 140 may be pulled out because there are too many holes 131 in the components 145 of the tubing string 140 for the sealing material 188 to effectively cover all of them at once. In addition, or in the alternative, the tubing string 140 may be pulled out because one or more of the holes 131 in the components 145 of the tubing string 140 are too large to be effectively covered by the sealing material 188. In addition, or in the alternative, the tubing string 140 may be pulled out because further production of the wellbore, even with a tubing string 140 with no holes 131, is no longer economical. The determination may be based, in part, on availability of a rig and / or other associated equipment, measurements made by one or more sensor devices 160, one or more algorithms, one or more protocols, and / or stored data. If the tubing string 140 is ready to be pulled out, then the process proceeds to step 1874. If the tubing string 140 is not ready to be pulled out, then the process reverts to step 1862.

[0119] In step 1874, faulty components 145 of the tubing string 140 are replaced. In other words, each component 145 with a hole 131 may be replaced. The faulty components 145 of the tubing string 140 may be replaced using a rig and / or other related equipment that is operated by one or more users 151 and / or a controller 104. When step 1874 is complete, the newly assembled tubing string 140 may be reinserted into the wellbore 110 to resume production operations, and the process proceeds to the END step. Alternatively, the process may revert to step 1861.

[0120] FIG. 19 shows a section of a substantially vertical section of a string 1940 used with a sample collection system according to certain example embodiments. Referring to the description above with respect to FIGS. 1 through 18, the substantially vertical section of the string 1940 of FIG. 19 shows that the section of the string 1940 does not need to be truly and completely vertical to be used with an example system (e.g., system 100). If the string 1940 forms an angle 1904 with a true vertical plane that is plus-or-minus 30°, then that part of the string 1940 is considered to be a substantially vertical section. If the angle 1904 is greater than plus-or-minus 30°, then that part of the string 1940 is not considered to be a substantially vertical section (e.g., horizontal, deviated).

[0121] FIG. 20 shows a block diagram of a computer device 2018 according to certain example embodiments. Specifically, FIG. 20 illustrates one embodiment of a computer device 2018 that implements one or more of the various techniques described herein, and which is representative, in whole or in part, of the elements described herein pursuant to certain example embodiments. For example, a controller 104 (including components thereof, such as a control engine, a hardware processor, a storage repository, a power module, and a transceiver) may be considered a computer device 2018. Computer device 2018 is one example of a computing device and is not intended to suggest any limitation as to scope of use or functionality of the computing device and / or its possible architectures. Neither should the computer device 2018 be interpreted as having any dependency or requirement relating to any one or combination of components illustrated in the example computer device 2018.

[0122] The computer device 2018 includes one or more processors or processing units 2014, one or more memory / storage components 2015, one or more input / output (I / O) devices 2016, and a bus 2017 that allows the various components and devices to communicate with one another. The bus 2017 represents one or more of any of several types of bus structures, including a memory bus or memory controller, a peripheral bus, an accelerated graphics port, and a processor or local bus using any of a variety of bus architectures. The bus 2017 includes wired and / or wireless buses.

[0123] The memory / storage component 2015 represents one or more computer storage media. The memory / storage component 2015 includes volatile media (such as random access memory (RAM)) and / or nonvolatile media (such as read only memory (ROM), flash memory, optical disks, magnetic disks, and so forth). The memory / storage component 2015 includes fixed media (e.g., RAM, ROM, a fixed hard drive, etc.) as well as removable media (e.g., a Flash memory drive, a removable hard drive, an optical disk, and so forth).

[0124] One or more I / O devices 2016 allow a user 151 to enter commands and information to the computer device 2018, and also allow information to be presented to the user 151 and / or other components or devices. Examples of input devices include, but are not limited to, a keyboard, a cursor control device (e.g., a mouse), a microphone, a touchscreen, and a scanner. Examples of output devices include, but are not limited to, a display device (e.g., a monitor or projector), speakers, outputs to a lighting network (e.g., DMX card), a printer, and a network card.

[0125] Various techniques are described herein in the general context of software or program modules. Generally, software includes routines, programs, objects, components, data structures, and so forth that perform particular tasks or implement particular abstract data types. An implementation of these modules and techniques is stored on or transmitted across some form of computer readable media. Computer readable media is any available non-transitory medium or non-transitory media that is accessible by a computing device. By way of example, and not limitation, computer readable media includes “computer storage media”.

[0126] “Computer storage media” and “computer readable medium” include volatile and non-volatile, removable and non-removable media implemented in any method or technology for storage of information such as computer readable instructions, data structures, program modules, or other data. Computer storage media include, but are not limited to, computer recordable media such as RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium which is used to store the desired information and which is accessible by a computer.

[0127] The computer device 2018 (also sometimes called a computer system herein) is connected to a network (not shown) (e.g., a LAN, a WAN such as the Internet, cloud, or any other similar type of network) via a network interface connection (not shown) according to some example embodiments. Those skilled in the art will appreciate that many different types of computer systems exist (e.g., desktop computer, a laptop computer, a personal media device, a mobile device, such as a cell phone or personal digital assistant, or any other computing system capable of executing computer readable instructions), and the aforementioned input and output means take other forms, now known or later developed, in other example embodiments. Generally speaking, the computer device 2018 includes at least the minimal processing, input, and / or output means necessary to practice one or more embodiments.

[0128] Further, those skilled in the art will appreciate that one or more elements of the aforementioned computer device 2018 is located at a remote location and connected to the other elements over a network in certain example embodiments. Further, one or more embodiments are implemented on a distributed system having one or more nodes, where each portion of the implementation (e.g., a system 100) is located on a different node within the distributed system. In one or more embodiments, the node corresponds to a computer system. Alternatively, the node corresponds to a processor with associated physical memory in some example embodiments. The node alternatively corresponds to a processor with shared memory and / or resources in some example embodiments.

[0129] FIGS. 21 through 25 show the use of example embodiments with part of another wellbore 2110 over time according to certain example embodiments. Specifically, FIGS. 21 through 25 show the wellbore 2110 during a conventional gas lift operation, where the annulus 2138 is used to push the fluid 2133 downhole and the cavity 2139 of the tubing string 2140 is used to produce the fluid 2134. Referring to the description above with respect to FIGS. 1 through 20, FIG. 21 shows a sectional view of part of the wellbore 2110 with which example embodiments may be used. The part of the wellbore 2110 shown in FIG. 21 includes part of a casing string 2125 that borders the wellbore 2110 with a subterranean formation 2120. Positioned inside the casing string 2125 is part of a tubing string 2140 that includes four components 2145 (component 2145-1, component 2145-2, component 2145-3, and component 2145-4). Each of the components 2145 of the wellbore 2110 of FIG. 21 may be substantially the same as the corresponding components of the systems (e.g., system 100 of FIG. 1) discussed above. At the point in time captured in FIG. 21, none of the four components 2145 has a hole (e.g., hole 131, hole 331) in its walls. Under these circumstances, as a fluid 2133 (e.g., a liquid, a pressurized gas) is pumped down the annulus 2138 (e.g., by the wellbore circulation equipment 150, by the pressure control equipment 135) at a pressure P1, a produced fluid 2134 (which includes a subterranean resource) travels up the cavity 2139 of the tubing string 2140 at a pressure P2 for extraction from the wellbore 2110.

[0130] Over time, one or more of the components 2145 of the tubing string 2140 develop a hole (e.g., hole 131, hole 331). FIG. 22 shows a sectional view of the part of the wellbore 2110 of FIG. 21 at a subsequent time when a hole 2231 has developed in one of the tubing string components 2145 according to certain example embodiments. Specifically, component 2145-2 (e.g., a tubing string pipe, a SPM) has a hole 2231 in its wall. As a result of the hole 2231, the pressure P3 in the annulus 2138 has decreased from the pressure P1 of FIG. 21. Consequently, as the fluid 2133 is pumped down the annulus 2138 at the pressure P3, little if any of the produced fluid 2134 travels up the cavity 2139 of the tubing string 2140 for extraction from the wellbore 2110. In other words, production is greatly reduced or stopped as a result of the hole 2231 in the component 2145-2 of the tubing string 2140. In the current art, either the wellbore 2110 would be abandoned or the tubing string 2140 would be pulled out of the wellbore 2110 to replace the component 2145-2. The former option results in lost production opportunity, and the latter option results in down time and high costs. The down time of the latter option may be extended if a rig required to trip out and back in the wellbore 2110 is not on site and available.

[0131] Use of example embodiments provides a solution to the situation presented in FIG. 22 that completely or substantially restores production with negligible down time, no need for a rig and related equipment, and minimal cost of implementation. FIG. 23 shows a sectional view of the part of the wellbore 2110 of FIG. 22 at a subsequent time when an attempt to cover the hole 2231 is being made according to certain example embodiments. Specifically, one or more (in this case, three) pieces of sealing material 2388 (sealing material 2388-1, sealing material 2388-2, and sealing material 2388-3) may be introduced (e.g., dropped) into the annulus 2138 of the tubing string 2140. For example, a crown valve of the Xmas tree (e.g., Xmas tree 195) may be opened (provided that there is a sufficient isolation valve), and the sealing material 2388 may be introduced into (e.g., dropped down) the annulus 2138 (or, in alternative embodiments, into the cavity 2139). As another example, a specialized injection device rated for pressure and incorporated into the wellbore circulation equipment (e.g., wellbore circulation equipment 150) may be used to introduce the sealing material 2388 into the annulus 2138 (or, in alternative embodiments, into the cavity 239). At the time captured in FIG. 23, the pressure P3 within the annulus 2138 is less than the pressure P2 within the cavity 2139 of the tubing string 2140.

[0132] Similar to what was discussed above with respect to FIG. 4, in some cases, a procedure may be followed in an effort to slow the descent of the sealing materials 2388 within the annulus 2138. For example, one procedure may be to stop injecting pressurized gas into the wellbore 210 when the sealing materials 2388 are introduced into the annulus 2138. Once the sealing materials 2388 are in the annulus 2138, a gas may be injected at a low pressure and a low flow rate until the hole 2231 is at least substantially covered by one of the sealing materials 2388. Once the hole 2231 is covered by the sealing material 2388-1, a sensor device (e.g., sensor device 160) measures an increase in pressure as an indication that the hole 2231 is, in fact, covered. At that time, the gas pressure may be increased to help secure the sealing material 2388-1 to the hole 2231.

[0133] As another example, with the wellbore 2110 temporarily taken out of service, any gas lift is stopped, and the pressure in the annulus 2138 is bled down. Then, the pressure P3 within the annulus 2138 may be increased (e.g., to 1000 psi) using gas lift gas. Then, once the sealing materials 2388 are introduced (e.g., dropped) into the annulus 2138, a gas lift injection (e.g., at 500 mcfpd) down the annulus 2138 may commence while also rapidly bleeding down the pressure P2 within the cavity 2139 of the tubing string 2140 and opening the flowline. This environment encourages a sealing material 2388 to cover the hole 2231.

[0134] As yet another example, oil, water, and / or condensate may be pumped down the annulus 2138. At some point, the pumping is stopped, and the sealing materials 2388 are introduced into the annulus 2138. The oil, water, and / or condensate slow the velocity of the sealing materials 2388. Then, a gas lift injection (e.g., at 500 mcfpd) down the annulus 2138 may commence to help encourage one of the sealing materials 2388 to cover the hole 2231. In some cases, one or more other liquids may additionally or alternatively be used to control the velocity of the sealing material 2388 and better place the sealing material 2388 relative to the hole 2231.

[0135] As discussed above, in certain example embodiments, a controller (e.g., controller 104) and / or a user (e.g., user 151) may be used to determine one or more of a number of factors for implementing example embodiments. Examples of such factors may include, but are not limited to, what type of sealing material 2388 to use, how much sealing material 2388 to introduce into the wellbore 110, the optimal size or range of sizes of the sealing material 2388, the target flow rate, pressure, and / or temperature of the fluid 2133 injected into the wellbore 110, the content (e.g., water, condensate, gas, liquid) of the fluid 2133 injected into the wellbore 110, and the concentration and / or amount of each content element of the fluid 2133, A controller and / or a user may balance or optimize these factors in light of gravity, drag, and / or suction force in an effort to ensure that the suction force through the hole 2231 is sufficient to overcome the inertia of the sealing material 2388 and allow the sealing material 2388 to cover the hole 2231 without being dislodged.

[0136] FIG. 24 shows a sectional view of the part of the wellbore 2110 of FIG. 23 at a subsequent time when the hole 2231 becomes covered according to certain example embodiments. Specifically, as sealing material 2388-1 falls due to gravity and the flow of the fluid within the annulus 2138, the force applied through the hole 2231 bv the differential between the pressure P2 within the cavity 2139 of the tubing string 2140 and the pressure P3 within the annulus 2138 (maintained by continuing to inject the fluid 2133 into the cavity 2139 of the tubing string 2140). As a result, sealing material 2388-1 is sucked against the wall of the component 2145-2 of the tubing string 2140, thereby covering or substantially covering the hole 2231. Sealing material 2388-2 and sealing material 2388-3 continue their gravity-assisted and fluid-assisted (from the fluid 2133) descent through the annulus 2138 toward the bottom of the wellbore 2110. When sealing material 2348-1 covers the hole 2231, the pressure P1 returns to the annulus 2138.

[0137] FIG. 25 shows a sectional view of the part of the wellbore 2110 of FIG. 24 at a subsequent time when the hole 2231 remains covered during production operations according to certain example embodiments. Specifically, once the hole 2231 is covered by the sealing material 2388-1, the pressure P1 within the annulus 2138 returns to what it was at the time captured in FIG. 21 before the hole 2231 emerged. As a result, by continuing to inject the fluid 2133 into the annulus 2138, the produced fluid 2134 traveling up the cavity 2139 of the tubing string 2140 is able to reach the surface (e.g., surface 108) because of the elevated pressure P1 and improved flow rate in the cavity 2139 of the tubing string 2140.

[0138] In a manner similar to what is described above and shown with respect to FIGS. 7 through 17, some or all of the sealing material 2348 (e.g., sealing material 2348-1) of FIGS. 21 through 25 may be dislodged from a hole (e.g., hole 2231) in the tubing string 2140 and / or disintegrated in the annulus 2138 to uncover a hole 2231 in the tubing string 2140 using pressure, temperature, one or more chemical additives, flow rate of the fluid 2133, and / or the passage of time.

[0139] Example embodiments can be used to mitigate a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore. The subterranean wellbore may be in production operations when example embodiments are used. Example embodiments may be used for land-based or subsea projects. Example embodiments may be used to cover leaks in a tubing string without significantly stopping operations and / or without urgently tripping out the tubing string to replace components. Example embodiments may be used for production operations where fluids are pumped downhole through the annulus or through the cavity of the tubing string. Example embodiments may include sensing capability to detect leaks caused by holes in real time and to determine when holes have been effectively covered by example sealing material in real time. Example embodiments also provide a number of other benefits. Such other benefits can include, but are not limited to, less down time, improved production output, more reliable operations, time savings, cost savings, and compliance with applicable industry standards and regulations.

[0140] Although embodiments described herein are made with reference to example embodiments, it should be appreciated by those skilled in the art that various modifications are well within the scope and spirit of this disclosure. Those skilled in the art will appreciate that the example embodiments described herein are not limited to any specifically discussed application and that the embodiments described herein are illustrative and not restrictive. From the description of the example embodiments, equivalents of the elements shown therein will suggest themselves to those skilled in the art, and ways of constructing other embodiments using the present disclosure will suggest themselves to practitioners of the art. Therefore, the scope of the example embodiments is not limited herein.

Claims

1. A method for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore, the method comprising:introducing, from above an entry point of the subterranean wellbore, a sealing material into a cavity of the tubing string within the subterranean wellbore, wherein the sealing material comprises string-like features and is configured to cover, based on a differential in pressure between the cavity of the tubing string and an annulus between the tubing string and a casing string, the hole in a wall in a component of the substantially vertical section of the tubing string, wherein the sealing material is configured to dissolve when exposed to an environmental condition within the subterranean wellbore, and wherein the hole in the wall of the component develops as a result of a failure in the wall during production operations.

2. The method of claim 1, further comprising:determining that the hole remains open after the sealing material is dropped down the cavity while the tubing string remains in the subterranean wellbore;generating a second sealing material by reducing a size of the sealing material not yet introduced into the cavity of the tubing string; andintroducing, from above the entry point of the subterranean wellbore, the second sealing material into the cavity of the tubing string, wherein the second sealing material comprises the string-like features and is configured to cover, based on the differential in pressure between the cavity of the tubing string and the annulus, the hole in the wall of the component of the substantially vertical section of the tubing string.

3. The method of claim 1, further comprising:determining that the hole remains open after the sealing material is introduced into the cavity; andintroducing, from above the entry point of the subterranean wellbore, additional sealing material into the cavity of the tubing string, wherein the additional sealing material is configured to cover, based on the differential in pressure between the cavity of the tubing string and the annulus, the hole in the wall of the component of the substantially vertical section of the tubing string.

4. The method of claim 1, further comprising:determining, after the sealing material covers the hole in the component, that an additional hole exists in a wall of an additional component of the substantially vertical section of the tubing string; andintroducing, from above the entry point of the subterranean wellbore, additional sealing material into the cavity of the tubing string, wherein the additional sealing material is configured to cover, based on the differential in pressure between the cavity of the tubing string and the annulus, the additional hole in the wall of the additional component of the substantially vertical section of the tubing string.

5. The method of claim 1, further comprising:controlling an environment within the subterranean wellbore as the sealing material is introduced into the cavity of the tubing string to reduce a velocity of the sealing material as the sealing material passes by the hole.

6. The method of claim 5, wherein controlling the environment within the subterranean wellbore comprises injecting a gas into the cavity of the tubing string at a controlled pressure.

7. The method of claim 5, wherein controlling the environment within the subterranean wellbore comprises pumping condensate down the tubing before introducing the sealing material into the cavity.

8. The method of claim 1, wherein the subterranean wellbore is taken out of service before the sealing material is introduced into the cavity.

9. The method of claim 1, wherein the environmental condition is normal wellbore conditions over a period of time.

10. The method of claim 1, further comprising:adding, from above the entry point of the subterranean wellbore a period of time after the sealing material covers the hole, a chemical additive into the subterranean wellbore, wherein the chemical additive creates the environmental condition that disintegrates the sealing material.

11. The method of claim 1, further comprising:increasing, using equipment above the entry point of the subterranean wellbore a period of time after the sealing material covers the hole, a temperature within the subterranean wellbore that exceeds a threshold temperature value within the subterranean wellbore, wherein the temperature creates the environmental condition that disintegrates the sealing material.

12. The method of claim 1, further comprising:increasing, using equipment above the entry point of the subterranean wellbore a period of time after the sealing material covers the hole, a pressure within the subterranean wellbore that exceeds a threshold pressure value within the subterranean wellbore, wherein the pressure creates the environmental condition that disintegrates the sealing material13. The method of claim 1, wherein the component of the substantially vertical section of the tubing string comprises at least one of a group consisting of a gas lift mandrel and a tubing pipe.

14. (canceled)15. The method of claim 1, wherein the sealing material further comprises a material component that activates once the sealing material covers the hole.

16. A system for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore, the system comprising:a sensor device configured to measure a pressure within the subterranean wellbore in an area of the substantially vertical section of the tubing string; anda receptacle in which a sealing material is disposed, wherein the sealing material comprises string-like features and is configured to be removed from the receptacle when the pressure measured by the sensor device falls outside a range of acceptable values, wherein the sealing material is further configured to be introduced, from above an entry point of the subterranean wellbore after being removed from the receptacle, into a cavity of the tubing string within the subterranean wellbore, wherein the sealing material is further configured to cover, based on a differential in pressure between the cavity of the tubing string and an annulus between the tubing string and a casing string, the hole in a wall in a component of the substantially vertical section of the tubing string, wherein the sealing material is configured to dissolve when exposed to an environmental condition within the subterranean wellbore, and wherein the hole in the wall of the component develops as a result of a failure in the wall during production operations.

17. The system of claim 16, further comprising:a second receptacle in which a chemical additive is disposed, wherein the chemical additive is configured, once removed from the second receptacle, to be added, from above the entry point of the subterranean wellbore a period of time after the sealing material covers the hole, into the subterranean wellbore, and wherein the chemical additive creates the environmental condition that disintegrates the sealing material.

18. The system of claim 16, further comprising:pressure control equipment located above the entry point of the subterranean wellbore and configured to control a pressure within the subterranean wellbore, wherein the pressure creates the environmental condition that disintegrates the sealing material when the pressure control equipment increases the pressure within the subterranean wellbore above a threshold pressure value.

19. The system of claim 16, further comprising:temperature control equipment located above the entry point of the subterranean wellbore and configured to control a temperature within the subterranean wellbore, wherein the temperature creates the environmental condition that disintegrates the sealing material when the temperature control equipment increases the temperature within the subterranean wellbore above a threshold temperature value.

20. The system of claim 16, further comprising:a controller communicably coupled to the sensor device, wherein the controller is configured to identify the leak caused by the hole in the wall in the component of the substantially vertical section of the tubing string based on the pressure measured by the sensor device.

21. A method for mitigating a leak from a hole in a substantially vertical section of a tubing string within a subterranean wellbore, the method comprising:introducing, from above an entry point of the subterranean wellbore, a sealing material into an annulus between the tubing string and a casing string within the subterranean wellbore, wherein the sealing material comprises string-like features and is configured to cover, based on a differential in pressure between a cavity of the tubing string and the annulus between the tubing string and the casing string, the hole in a wall in a component of the substantially vertical section of the tubing string, and wherein the hole in the wall of the component develops as a result of a failure in the wall during production operations.

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