Spinning diamond broach

Abstract

Embodiments of the present invention relate to a pattern of grooves and peaks that cause an oilfield tool to rotate or spin as it ascends and / or descends in a wellbore. This rotating / spinning action can better remove corrosion / build-up on the wellbore walls. The pattern can include three primary characteristics: rifled grooves; crosshatch grooves; and peaks. Rifled grooves can constitute a series of spiral or helical grooves cut (or otherwise formed) into an exterior surface of device. These grooves are designed to impart a spin to the device as it ascends and / or descends in a wellbore. This spin stabilizes the plunger's movement, while also causing cutting edges on the peaks (created by the combination of rifled grooves and crosshatch grooves) to better remove corrosion / build-up on the walls of a wellbore than known prior art designs.

Description

PRIORITY CLAIM

[0001] This application claims priority to provisional patent application Ser. No. 63 / 681,439, filed Aug. 9, 2024, which is fully incorporated herein by reference.BACKGROUNDTechnical Field

[0002] Embodiments of the subject matter disclosed herein relate to a tool for cleaning tubing walls as the tool traverses the tubing, and more specifically to an improved artificial lift device for doing the same in the production string of an oil and gas well.Discussion Of The Background

[0003] The production string in an oil and gas well, a vital conduit for transporting hydrocarbons from their underground reservoir to the surface, is susceptible to corrosion and deposit build-up, which can severely impair well productivity. These phenomena result from complex interactions between the metal tubing, produced fluids, and environmental conditions within the well. Corrosion, which is an electrochemical process, degrades the steel tubing, while deposit build-up, or scale formation, obstructs flow by accumulating solids on the tubing walls. Both issues reduce the efficiency and longevity of the well, leading to costly interventions and production losses.

[0004] Corrosion in the production string occurs when the steel walls of the tubing react with corrosive agents in the produced fluids, primarily water, gases, and chemicals. Water, often saline, acts as an electrolyte, facilitating electrochemical reactions that degrade the metal. High chloride concentrations in produced water increase fluid conductivity, accelerating corrosion. Carbon dioxide, when dissolved in water, forms carbonic acid, lowering the pH and causing sweet corrosion, which manifests as uniform or localized metal loss. Hydrogen sulfide, another prevalent gas, induces sour corrosion, leading to pitting and potentially catastrophic cracking, such as sulfide stress cracking in susceptible alloys. The combination of these gases creates a highly aggressive environment, particularly in wells with mixed CO2 and H2S presence.

[0005] Temperature and pressure further influence corrosion rates. Elevated temperatures, common in deeper wells, accelerate chemical reactions, though in some cases, they reduce gas solubility, altering corrosion dynamics. High pressure increases the solubility of corrosive gases, intensifying their impact. Flow dynamics, such as turbulent or stagnant flow, can exacerbate corrosion by removing protective films or concentrating corrosive agents at specific points. Microbiological activity, particularly from sulfate-reducing bacteria, compounds the problem by producing hydrogen sulfide as a metabolic byproduct, contributing to sour corrosion and localized damage through biofilm formation.

[0006] Deposit build-up, on the other hand, occurs when minerals or organic solids precipitate from the produced fluids and adhere to the production tubing walls. Common inorganic scales include calcium carbonate, calcium sulfate, and barium sulfate, which form due to changes in pressure, temperature, or fluid chemistry. As fluids travel through the production string, pressure decreases, reducing the solubility of minerals and causing precipitation. Temperature changes also can trigger the deposition of calcium carbonate, which becomes less soluble at higher temperatures. Mixing of incompatible fluids, such as formation water rich in barium and seawater containing sulfate, leads to the rapid formation of insoluble barium sulfate scales. Organic deposits, such as paraffins and asphaltenes, also contribute to build-up. Paraffins precipitate when crude oil cools below its cloud point, forming waxy layers, while asphaltenes, heavy hydrocarbon fractions, deposit due to changes in pressure or composition. Microbial activity further promotes deposition by forming biofilms that trap minerals and organic material, creating a matrix that encourages further build-up. Corrosion products, such as iron oxides or sulfides, can also act as deposits, compounding the obstruction in production tubing.

[0007] The composition of corrosion products depends on the corrosive environment. In CO2-dominated systems, iron carbonate forms, creating a scale-like layer that may offer partial protection but is often porous and ineffective. In H2S-rich environments, iron sulfides dominate, causing pitting and cracking. Pitting corrosion is particularly damaging, as it creates deep, localized holes that weaken the tubing. Inorganic scales like calcium carbonate, calcium sulfate, and barium sulfate are crystalline and highly insoluble, forming hard, adherent layers. Iron-based deposits, resulting from corrosion or microbial activity, add to the complexity. Organic deposits, such as paraffins, are waxy and softer, while asphaltenes are amorphous and sticky, adhering tenaciously to surfaces. These varied compositions create a challenging environment, as different deposits require specific removal strategies.

[0008] Corrosion and deposit build-up significantly reduce well productivity by compromising the structural integrity and flow capacity of the production string. Corrosion weakens the tubing, leading to leaks, perforations, or complete failure, necessitating costly workovers to replace damaged sections. Pitting corrosion creates weak points that may fail under pressure, posing safety risks like blowouts or environmental spills. Deposits reduce the internal diameter of the tubing, restricting hydrocarbon flow and increasing pressure drop, which lowers production rates. Severe build-up can completely block the tubing, halting production entirely. Deposits also interfere with downhole equipment, such as pumps or valves, reducing their efficiency and increasing energy costs. The interplay between corrosion and deposits exacerbates these issues, as corrosion products contribute to build-up, and deposits create microenvironments that accelerate corrosion. This synergy can rapidly degrade well performance, making timely intervention critical.

[0009] Mitigating corrosion involves a combination of material selection, chemical treatments, and operational strategies. Corrosion-resistant alloys, such as stainless steel or nickel-based alloys, are used in high-risk wells to withstand aggressive environments, though their high cost limits widespread adoption. Carbon steel, more cost-effective, is commonly used but requires additional protection. Chemical corrosion inhibitors, such as amine-based compounds or organic phosphates, are injected into the production stream to form a protective film on the metal surface, reducing contact with corrosive agents. These inhibitors are applied continuously or in batches, with their effectiveness depending on fluid chemistry and flow conditions. Cathodic protection, where an electric current or sacrificial anode is used to counteract the electrochemical reaction, is occasionally applied, particularly for external tubing surfaces. Coating the tubing with protective layers, such as epoxy or polymer linings, provides a physical barrier against corrosive fluids, though these coatings must withstand high temperatures and mechanical wear.

[0010] Controlling deposit build-up requires both preventive and remedial approaches. Scale inhibitors, such as phosphonates or polymer-based chemicals, can be injected to prevent mineral precipitation by interfering with crystal formation. These inhibitors are tailored to the specific chemistry of the produced fluids and are most effective when applied before significant scaling occurs. Thermal methods, such as hot oiling or hot water injection, can be used to dissolve paraffin deposits by raising the temperature above the paraffin's melting point. Chemical solvents, like xylene or toluene, can be effective for removing organic deposits like asphaltenes, though their use requires careful handling due to environmental and safety concerns. Mechanical methods, such as wireline tools, certain plungers, or coiled tubing, physically remove deposits by scraping or jetting the tubing walls. These methods are effective for hard scales but can be costly and risk damaging the tubing.

[0011] Acidizing is another widely used remedial technique to dissolve inorganic scales and corrosion products. Hydrochloric acid is commonly used for calcium carbonate scales, while hydrofluoric acid or chelating agents are employed for more complex scales like barium sulfate. Acid treatments must be carefully designed to avoid damaging the tubing or formation, and corrosion inhibitors are often added to protect the metal during the process. For microbial-related issues, biocides can be applied to control sulfate-reducing bacteria and prevent biofilm formation. Continuous monitoring of fluid chemistry and corrosion rates, using techniques like coupon testing or electrochemical sensors, allows operators to detect problems early and adjust mitigation strategies accordingly.

[0012] The choice of mitigation method depends on the well's specific conditions, including fluid composition, temperature, pressure, and economic considerations. Preventive measures, such as inhibitor injection and material selection, are generally more cost-effective than remedial treatments, which often require production shutdowns. However, no single method is universally effective, and a combination of strategies is typically employed to address both corrosion and deposits. Advances in technology, such as real-time monitoring systems and environmentally friendly inhibitors, are improving the ability to manage these issues, but challenges remain in balancing cost, effectiveness, and environmental impact.

[0013] As described below in more detail, the present invention improves on at least one of the above-described techniques for ameliorating buildup on tubing walls, whether by corrosion and / or other deposits.BRIEF DESCRIPTION OF THE DRAWINGS

[0014] The following disclosure may be understood by reference to the description herein taken in conjunction with the accompanying drawings, in which like reference numerals identify like elements. The accompanying drawings, which are incorporated herein and constitute a part of the specification, illustrate one or more exemplary embodiments of the present invention, except where the drawings are indicated to illustrate the prior art. The present invention should not be considered limited to the following drawings. In the drawings:

[0015] FIG. 1 is a perspective view of one embodiment of a prior art plunger sleeve;

[0016] FIG. 2 is side view of FIG. 1, including cross-section line 3-3;

[0017] FIG. 3 is a cross-section of FIG. 2 along cross-section line 3-3 in FIG. 2;

[0018] FIG. 4 is and end view of FIG. 1;

[0019] FIG. 5 is a perspective view of one embodiment of a prior art bar-stock style plunger;

[0020] FIG. 6 is side view of FIG. 5 including cross-section line 7-7;

[0021] FIG. 7 is a cross-section of FIG. 6 along cross-section line 7-7 in FIG. 6;

[0022] FIG. 8 is and end view of FIG. 5;

[0023] FIG. 9 is a perspective view of an embodiment of a dart plunger including an embodiment of the present invention;

[0024] FIG. 10 is side view of FIG. 9, including cross-section line 11-11;

[0025] FIG. 11 is a cross-section of FIG. 10 along cross-section line 11-11 in FIG. 10;

[0026] FIG. 12 is an end view of FIG. 9;

[0027] FIG. 13 is a perspective view of one embodiment of a plunger sleeve including an embodiment of the present invention;

[0028] FIG. 14 is side view of FIG. 13, including cross-section line 15-15;

[0029] FIG. 15 is a cross-section of FIG. 14 along cross-section line 15-15 in FIG. 14;

[0030] FIG. 16 is an end view of FIG. 13;

[0031] FIG. 17 is a perspective view of one embodiment of a bar-stock style plunger including an embodiment of the present invention;

[0032] FIG. 18 is side view of FIG. 17, including cross-section line 19-19;

[0033] FIG. 19 is a cross-section of FIG. 18 along cross-section line 19-19 in FIG. 18; and

[0034] FIG. 20 is an end view of FIG. 17.DETAILED DESCRIPTION

[0035] Various features and advantageous details are explained more fully with reference to the non-limiting embodiments that are illustrated in the accompanying drawings and detailed in the description herein. Descriptions of well-known starting materials, processing techniques, components, and equipment are omitted so as not to unnecessarily obscure the invention. It should be understood, however, that the detailed description and the specific examples, while indicating embodiments of the invention, are given by way of illustration only, and not by way of limitation. Various substitutions, modifications, additions, and / or rearrangements within the spirit and / or scope of the underlying inventive concept will become apparent to those skilled in the art from this disclosure.

[0036] The words and phrases used herein should be understood and interpreted to have a meaning consistent with the understanding of those words and phrases by those skilled in the relevant art. No special definition of a term or phrase, i.e., a definition that is different from the ordinary and customary meaning as understood by those skilled in the art, is intended or implied. To the extent that a term or phrase is intended to have a special meaning, i.e., a meaning other than that understood by skilled artisans, such special definition will be expressly set forth in the specification in a definitional manner that directly and unequivocally provides the special definition for the term or phrase.

[0037] FIG. 1 is a perspective view of one embodiment of prior art plunger sleeve 10. Those skilled in the art will appreciate how a plunger operates in traveling up and down a production tubing string to remove liquids from the string, thereby increasing the well's efficiency. See e.g., U.S. Pat. No. 9,683,430, which is incorporated herein by reference. Those skilled in the art also will appreciate that a variety of types of plungers exist including, but not limited to, ball plungers, ball-and-sleeve plungers, rod plungers, dart plungers, etc. Some of those plungers are illustrated here for exemplary purposes, although it should be recognized that the present invention is not limited to artificial lift devices, including plungers, but rather to any suitable tool for removing corrosion / build-up from tubing walls.

[0038] The prior art embodiment shown in FIG. 1 illustrates plunger 10 including a patterned outside surface at one end of the plunger sleeve consisting of a series of peaks 15 and rounded grooves 16. Some have called this a “diamond” patten due to the raised shape(s) resulting from the series of peaks 15 and grooves 16. This pattern, consisting of the arranged, as-shown peaks 15 and grooves 16, has been demonstrated to assist (via a scraping action) in removing corrosion and / or buildup on production tubing walls as the plunger ascends and descends in the tubing. However, this plunger (and its associated pattern) has proved somewhat inefficient in its ability to remove said corrosion / build-up, thereby leading the Applicant to investigate, design, and test a new pattern that is believed to be—and has proven to be—more efficient in its ability to remove (i.e., scrape away) said corrosion / build-up. The details of the present invention are described in more detail below in connection with FIGS. 9-20.

[0039] FIG. 2 is side view of FIG. 1, including cross-section line 3-3. FIG. 3 is a cross-section of FIG. 2 along cross-section line 3-3 in FIG. 2. As FIG. 3 shows, the pattern consisting of the series of peaks 15 and grooves 16 are machined into the sleeve such that peaks 15 are the same height and grooves 16 are the same depth. The outside diameter of sleeve 10 in the region of the series of peaks 15 and grooves 16 is at least as large as any other outside diameter of sleeve 10, thereby assuring that the patterned region of the sleeve contacts the walls of the production tubing to perform its scraping function. Finally, FIG. 4 is and end view of FIG. 1.

[0040] FIG. 5 is a perspective view of one embodiment of prior art bar-stock style plunger 20. As before with the prior art plunger described with respect to FIGS. 1-4, those skilled in the art will appreciate how a plunger operates in traveling up and down a production tubing string to remove liquids from the string, thereby increasing the well's efficiency. The prior art embodiment shown in FIG. 5 illustrates plunger 20 including a patterned outside surface toward opposite ends of the plunger consisting of a series of peaks 25 and rounded grooves 26. Here again, some have called this a “diamond” patten due to the raised shape(s) resulting from the series of peaks 25 and grooves 26. This pattern, consisting of the arranged, as-shown peaks 25 and grooves 26, has been demonstrated to assist (via a scraping action) in removing corrosion and / or buildup on production tubing walls as the plunger ascends and descends in the tubing. However, as with the sleeve shown in FIGS. 1-4, this plunger (and its associated pattern) has proved somewhat inefficient in its ability to remove said corrosion / build-up, thereby leading the Applicant to investigate, design, and test a new pattern that is believed to be—and has proven to be—more efficient in its ability to remove (i.e., scrape away) said corrosion / build-up.

[0041] FIG. 6 is side view of FIG. 5, including cross-section line 7-7. FIG. 7 is a cross-section of FIG. 6 along cross-section line 7-7 in FIG. 6. As FIG. 7 shows, the pattern consisting of the series of peaks 25 and grooves 26 are machined into the plunger such that peaks 25 are the same height and grooves 26 are the same depth. The outside diameter of plunger 20 in the region of the series of peaks 25 and grooves 26 is at least as large as any other outside diameter of sleeve 20, thereby assuring that the patterned regions of the plunger contact the walls of the production tubing to perform their scraping function. Finally, FIG. 8 is and end view of FIG. 5.

[0042] FIG. 9 is a perspective view of an embodiment of a plunger including an embodiment of the present invention. While this embodiment is that of a dart plunger, it should be appreciated that the present invention can be implemented in connection with any suitable tool, including artificial lift devices such as plungers (but not limited to those exemplified in FIGS. 9-20), or other suitable device that ascends and / or descends in a tubing bore. In that sense, and as exemplified by FIG. 9, an embodiment of the invention can be employed on a tool having a body, where the body has a first end, a second end, and a longitudinal axis that may extend from the first end to the second end. One of the keys to the present invention is the pattern employed on the outside of the exemplary plunger (or other tool) that operates to enable the tool to more efficiently and / or effectively remove corrosion / build-up on tubing walls than prior art devices.

[0043] As shown in the embodiment of FIG. 9, a non-limiting embodiment of the pattern includes three primary characteristics: rifled grooves 37; crosshatch grooves 36; and peaks 35. As shown, rifled grooves 37 can constitute a series of spiral or helical grooves cut (or otherwise formed) into an exterior surface of tool 30. These grooves are designed to impart a spin to plunger 30 around its longitudinal axis as it ascends and / or descends in a wellbore. This spin stabilizes the plunger's movement, while also causing cutting edges on peaks 35 (created by the combination of rifled grooves 37 and crosshatch grooves 36) to better remove (or clean) corrosion / build-up on the walls of a wellbore than the known prior art designs.

[0044] As indicated and as shown, in this embodiment rifled grooves 37 can have a depth greater than crosshatch grooves 36, the combination of which results in peaks 35 and the cutting edges associated therewith. The outside diameter of plunger 30 in the region of the series of grooves 37, crosshatch grooves 36, and peaks 35 is at least as large as any other outside diameter of plunger 30, thereby assuring that the patterned region of the plunger contacts the walls of the production tubing to perform its scraping / cleaning function. It should be understood, however, that rifled grooves 37 and crosshatch grooves 36 are not limited to the particular pattern disclosed herein. Their pattern (number, depth, and twist rate) can vary depending on the tool's design and intended / desired performance. Moreover, while FIG. 9 shows the pattern of rifled grooves 37, crosshatch grooves 36, and peaks 35 located toward the middle of the body of dart plunger 30, it should be appreciated that such pattern could be located at one or more other locations on the plunger or tool, non-limiting examples of which are shown in FIGS. 13-20. Still further, rifled grooves 37 and / or crosshatch grooves 36 can be rounded, square, or another shape as desired by the manufacturer since different shapes may impart better scraping / cleaning by changing the shape of the cutting edges on peaks 35. Alternatively, the cutting edges on peaks 35 can be machined or otherwise formed to assume whatever shape the designer prefers, which may be independent on the shape of rifled grooves 37 and / or crosshatch grooves 36. Finally, as those skilled in the art will appreciate, FIG. 10 is a side view of FIG. 9, including cross-section line 11-11; FIG. 11 is a cross-section of FIG. 10 along cross-section line 11-11 in FIG. 10; and FIG. 12 is an end view of FIG. 9.

[0045] FIG. 13 is a perspective view of an embodiment of plunger sleeve 40 including an embodiment of the present invention. Here, the same pattern deployed and described in connection with FIGS. 9-12 is oriented on one end of sleeve 40. As described in connection with FIGS. 9-12, rifled grooves 37 can constitute a series of spiral or helical grooves cut (or otherwise formed) into an exterior surface of device 40. These grooves are designed to impart a spin to sleeve 40 around its longitudinal axis as it ascends and / or descends in a wellbore. This spin stabilizes the sleeve's movement, while also causing cutting edges on peaks 35 (created by the combination of rifled grooves 37 and crosshatch grooves 36) to better remove corrosion / build-up on the walls of a wellbore than the known prior art designs. FIG. 14 is a side view of FIG. 13, including cross-section line 15-15; FIG. 15 is a cross-section of FIG. 14 along cross-section line 15-15 in FIG. 14; and FIG. 16 is an end view of FIG. 13.

[0046] FIG. 17 is a perspective view of an embodiment of bar-stock style plunger 50 including an embodiment of the present invention. Here, the same pattern deployed and described in connection with FIGS. 9-16 is oriented on one end of bar-stock style plunger 50. As described in connection with FIGS. 9-16, rifled grooves 37 can constitute a series of spiral or helical grooves cut (or otherwise formed) into an exterior surface of device 50. These grooves are designed to impart a spin to plunger 50 around its longitudinal axis as it ascends and / or descends in a wellbore. As before, this spin stabilizes the sleeve's movement, while also causing cutting edges on peaks 35 (created by the combination of rifled grooves 37 and crosshatch grooves 36) to better remove corrosion / build-up on the walls of a wellbore than the known prior art designs. FIG. 18 is a side view of FIG. 17, including cross-section line 19-19; FIG. 19 is a cross-section of FIG. 18 along cross-section line 19-19 in FIG. 18; and FIG. 20 is an end view of FIG. 17.

[0047] Although the invention(s) is / are described herein with reference to specific embodiments, various modifications and changes can be made without departing from the scope of the present invention(s), as set forth in the claims below. Accordingly, the specification and Figures are to be regarded in an illustrative rather than a restrictive sense, and all such modifications are intended to be included within the scope of the present invention(s). Any benefits, advantages, or solutions to problems that are described herein with regard to specific embodiments are not intended to be construed as a critical, required, or essential feature or element of any or all the claims.

[0048] Unless stated otherwise, terms such as “first” and “second” are used to arbitrarily distinguish between the elements such terms describe. Thus, these terms are not necessarily intended to indicate temporal or other prioritization of such elements. The terms “coupled” or “operably coupled” are defined as connected, although not necessarily directly, and not necessarily mechanically. The terms “a” and “an” are defined as one or more unless stated otherwise. The terms “comprise” (and any form of comprise, such as “comprises” and “comprising”), “have” (and any form of have, such as “has” and “having”), “include” (and any form of include, such as “includes” and “including”) and “contain” (and any form of contain, such as “contains” and “containing”) are open-ended linking verbs. As a result, a system, device, or apparatus that “comprises,”“has,”“includes” or “contains” one or more elements possesses those one or more elements but is not limited to possessing only those one or more elements. Similarly, a method or process that “comprises,”“has,”“includes” or “contains” one or more operations possesses those one or more operations but is not limited to possessing only those one or more operations.

[0049] Accordingly, the protection sought herein is as set forth in the claims below.

Claims

1. A tool for cleaning tubing walls as the tool traverses the tubing, wherein the tool comprises:a body having a first end, a second end, and a longitudinal axis; anda pattern on the body located between the first end and the second end, whereby said pattern induces the tool to spin around its longitudinal axis as the tool traverses the tubing.

2. The tool of claim 1 wherein the pattern includes a rifled groove.

3. The tool of claim 2 wherein the pattern further includes a crosshatch groove.

4. The tool of claim 3 wherein the pattern further includes a plurality of peaks formed by the rifled groove and the crosshatch groove.

5. The tool of claim 4 wherein at least some of the plurality of peaks include a cutting edge, wherein the cutting edge cleans the tubing walls as the tool traverses the tubing.

6. The tool of claim 5 wherein the rifled groove has a first depth, and the crosshatch groove has a second depth.

7. The tool of claim 6 wherein the first depth is deeper than the second depth.

8. The tool of claim 7 wherein the rifled groove comprises a plurality of rifled grooves.

9. The tool of claim 8 wherein the crosshatch groove comprises a plurality of crosshatch grooves.

10. The tool of claim 9 wherein the pattern is located at the first end of the tool.

11. The tool of claim 10 wherein the pattern is located at the first end of the tool and separately between the first end and the second end of the tool.

12. The tool of claim 11 wherein the tool is an artificial lift device.

13. The tool of claim 12 wherein the tool is a plunger.

14. The tool of claim 13 wherein the tubing walls comprise the walls of production tubing in an oil and gas well.

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