GAS WELL SYSTEM

CROSS REFERENCE TO RELATED APPLICATIONS [0001] This application claims the benefit of the filing date of U.S. Provisional Patent Application Serial No. 63/175,233, titled “SYSTEMS AND METHODS FOR CATHODIC PROTECTION OF AN OIL PUMPING SYSTEM,” filed April 15, 2021, the disclosure of which is hereby incorporated by this reference in its entirety.

FIELD OF THE DISCLOSURE

[0002] The present disclosure relates, according to some embodiments, to systems and methods of cathodic protection of an oil and gas well system ( e.g ., a pumping system) using an anodic coating.

BACKGROUND

[0003] Sucker rod pumping systems are commonly used artificial lifting systems for oil wells. Suckers rods can be used to implement a rotary or linear reciprocating motion that provides mechanical energy to lift oil from bottom-hole to surface for further processing and refinement.

[0004] However, many downhole components including sucker rods, tubing and pumps are made of carbon steel that readily corrodes when introduced to oil compositions containing water and corrosive agents (e.g., acids, oxidizers, bases) including H2S, CO2, O2, and chlorides. Corrosion of downhole components lead to pitting that may lead to fatigue and corrosion cracking of components that is formed at the base of a corrosion pit. This fatigue can be somewhat exacerbated by the cyclic loading nature of sucker rod- driven artificial lifting where cracks often initiate at high stress points on the sucker rod and can lead to a reduction in the rod cross-section to the point where the rod cannot carry the load and fails. Further, as many oil well systems age and use up the readily available oil deposits, operators must dig deeper to find more oil. Since the deeper oil reserves tend to contain hotter and more corrosive (e.g., acids, oxidizers, bases) fluids, digging deeper leads to even more corrosion on the downhole components causing sucker rod pumping system component failure. Also as wells age and production rates decrease, operators often use enhanced recovery methods such as water and steam flooding, or cyclic steam injection to help boost production. Unfortunately, these methods also introduce large amounts of H2O which increases corrosion.

[0005] Some known corrosion mitigation techniques involve the use of chemical corrosion inhibitors. While these inhibitors may have some effectiveness, they are often difficult to transport to the sites of corrosion and can often be incompatible with other downhole pump components such as elastomeric parts. Another strategy involves the use of metal alloys that are inherently more corrosion resistant than general carbon steel components. However, these alloys are generally not cost effective as their production cost outweighs their often incremental performance benefit.

[0006] A third method of protecting sucker rods includes coating the sucker rods with polymeric coatings that are protective against corrosive agents. These include thermoplastic polymer coatings ( e.g polyethylene) and thermosetting fusion bonded epoxy (FBE) coatings. The thermoplastic polymer coating technique does not bond well with the sucker rod surface and is prone to disbondment. This leads to a limitation of the depth of well in which this coated coiled rod string can be installed. The deeper the well, the more squeeze pressure the injector units, which deploy and retrieve coiled sucker rod strings from wells, need to hold onto the sucker rod strings. Since the thermoplastic polymer coating does not bond well enough, the squeeze pressure strips or sloughs off the polymer coating from the sucker rod surface. This is especially true when trying to retrieve the coated sucker rod string from the well after it has been down hole for any period of time. Once the thermoplastic polymer coating strips or sloughs off, the sucker rod metal is left unprotected and will begin to corrode. Additionally, thermoplastic polymer coating that has fallen off can plug flow lines. If the coating peels while in the well bore, the loose coating can plug the pump and/or the flow lines, leading to unwanted and expensive repairs.

[0007] Fusion bonded epoxy coatings provide a modest protection against corrosion caused by contact with down well chemicals, but such coatings are also subject to abrasion. Additionally, application of fusion bonded epoxy coating systems involves complicated, timely, and costly procedures. As these coatings are worn, corrosion protection is lost and repairs to such systems are problematic and expensive.

[0008] Another downfall of known sucker rod corrosion protection methods is that they generally protect only the sucker rods and leave other downhole components prone to corrosion and degradation. Therefore, systems and methods are needed that not only protect the sucker rods, but that also protect other system components against corrosive agents. Additionally, systems and methods are needed that are operable to protect downhole components even after both physical wear and corrosion has occurred on the sucker rods.

SUMMARY

[0009] In some aspects, the techniques described herein relate to a sucker rod pumping system for cathodic protection of components, the system including: an anode including an anodic coating on a surface of a body of a sucker rod string including one or more sucker rods; and a cathode including one or more of: a tubing string including a cylinder and configured to concentrically contain the sucker rod string, a polished rod, and a pump; the polished rod configured to be connected to a polished rod clamp above ground and to be connected to a top end of the sucker rod string contained below the ground; or the pump mechanically connected to a bottom end of the sucker rod string, wherein the anode is configured to at least partially inhibit corrosion of the cathode.

[0010] In some aspects, the techniques described herein relate to a method for cathodic protection using the sucker rod pumping systems discussed in this section.

[0011] In some aspects, the techniques described herein relate to a system for cathodic protection of one or more components of an oil and gas well, the system including: an anode including an anodic coating on a surface of at least one first component of the oil and gas well; a cathode including at least one second component of the oil and gas well that is connected to and configured to be positioned in a location that is uphole or downhole from the at least one first component; and at least one electrically conductive connection line electrically coupling the at least one first component and the at least one second component, wherein the anode is configured to at least partially inhibit corrosion of the cathode. [0012] In some aspects, the techniques described herein relate to a method for cathodic protection of components of a sucker rod pumping system, the method including: applying an anodic coating on a surface of at least one first component of the oil and gas well to form an anode component; electrically connecting, via a conductive connection, the anode component to a cathode component including at least one second component of the oil and gas well; and at least partially inhibiting corrosion of the cathode component with the anode component.

[0013] Features from any of the disclosed embodiments may be used in combination with one another, without limitation. In addition, other features and advantages of the present disclosure will become apparent to those of ordinary skill in the art through consideration of the following detailed description and the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS [0014] The drawings illustrate several embodiments of the present disclosure, wherein identical reference numerals refer to identical or similar elements or features in different views or embodiments shown in the drawings.

[0015] FIGURE 1 is an elevational view of a pumping system according to embodiments of the disclosure.

[0016] FIGURE 2 is an elevational view of a pumping system according to embodiments of the disclosure.

[0017] FIGURE 3 illustrates a cross-sectional view of a coating on at least one component of an oil and gas well according to embodiments of the disclosure.

[0018] FIGURE 4 illustrates a cross-sectional view of a coating on at least one component of an oil and gas well according to embodiments of the disclosure.

DETAILED DESCRIPTION

[0019] As used herein, relational terms, such as “first,” “second,” “top,” “bottom,” etc., are generally used for clarity and convenience in understanding the disclosure and accompanying drawings and do not connote or depend on any specific preference, orientation, or order, except where the context clearly indicates otherwise. [0020] As used herein, the term “and/or” means and includes any and all combinations of one or more of the associated listed items.

[0021] As used herein, the terms “vertical,” “upper,” “lower,” and “lateral” refer to the orientations as depicted in the figures. Further, when used herein in reference to a location in, or relative to, a wellbore, the terms “above,” “upper,” and “uphole” mean and include a relative position proximate the surface of the well, whereas the terms “below,” “lower” and “downhole” mean and include a relative position distal the surface of the well.

[0022] The term “surface” may indicate the surface of the Earth on which a portion of pumping assembly for a well is positioned where the well or borehole extending through and below the surface.

[0023] The present disclosure relates to the application of an anodic coating ( e.g ., metal anodic coating) on a portion of either a coiled or conventional sucker rod that synergistically provides for a cathodic protection against corrosion for downhole and above-well components of a sucker rod pumping system. The anodic coating (e.g., aluminum, zinc, and/or magnesium) may act as a sacrificial anode that will corrode in place of sucker rod pumping system components acting as a cathode, thereby protecting the cathodic components from corrosion. Each of the sucker rod pumping system components may be electrically connected in a continuous circuit so that the corrosion protection provided to the sucker rod by the anodic coating will also provide similar protection to all other system components.

[0024] In some embodiments, in addition to providing corrosion protection to the sucker rod, an anodic coating may improve (e.g., decrease) the coefficient of friction by up to 25 % in comparison to the underlying metal alone, where the metal alone would exhibit a coefficient of friction that is greater than the coefficient of friction of the anodic coating. The relatively more soft, ductile, and malleable anodic coating may provide surfaces having a relatively lower coefficient of friction, more desirable wear, and self-healing characteristics as is discussed below.

[0025] Besides providing corrosive protection for down-well components, embodiments of the disclosed anodic coated sucker rods may advantageously exhibit self-healing properties in response to wear. As previously described, wear ruins the polymeric protective barriers of previously known systems by causing the barriers to slough off in chunks, thereby exposing the underlying metals. Instead of being removed in chunks, the disclosed anodic coating wears in small portions, which then self-heals through a smearing action of the coating to cover the sucker rod portions that were exposed through wear. Additionally, even when localized damage to portions of the anodic coating occurs, corrosion protection of system components is not disrupted since the anodic coating contacts the entire sucker rod string so that the electrical circuit created through galvanic coupling of the cathode and anode is not disrupted. For example, full cathodic protection may be provided by a system where from 30 % to 40 % of the anodic coating has been worn off.

[0026] Application of an anodic coating on a coiled or conventional sucker rod as is presented herein includes coating a portion of an entirety of sucker rod. For example, a sucker rod may have a surface that is about 0.1 % coated with the anodic coating, or about 5 % coated, or about 10 % coated, or about 15 % coated, or about 20 % coated, or about 25 % coated, about 30 % coated, or about 35 % coated, or about 40 % coated, or about 45 % coated, about 50 % coated, or about 55 % coated, or about 60 % coated, or about 65 % coated, or about 70 % coated, or about 75 % coated, or about 80 % coated, or about 85 % coated, or about 90 % coated, or about 95 % coated, or about 100 % coated, where about includes plus or minus 2.5 %. A coating may include any geometric design. A coating may be applied on a sucker rod as a longitudinal strip and as multiple longitudinal strips. For example, a coating may be applied on a sucker rod as two longitudinal strips that are diametrically opposed to each other. A coating may be applied circumferentially around a sucker rod. For example, a coating may be applied at one or more circumferential strips around a sucker rod. In some embodiments, coated sucker rods and non-coated sucker rods are connected in an alternative series along a sucker rod string.

[0027] A self-healing capability of disclosed cathodic protection methods and systems is in part driven by an inclusion of anodic coatings containing soft metals including aluminum, zinc, magnesium, and/or alloys thereof. Soft metal anodic coating compositions smear in the presence of heat and friction to recoat exposed sucker rod surfaces. Additionally, anodic coating made of relatively soft metals ( e.g aluminum) may wear away instead of spalling off in larger pieces or splinters as do conventional polymeric coatings ( e.g ., FBE and thermoplastic polymer coatings). Therefore, anodic coatings used herein will not generally plug up flow lines or contaminate production fluids. Additionally, anodic coatings according to embodiments disclosed herein do not tend to as readily spall off of the sucker rod surfaces while being serviced as compared to either fusion bonded epoxy or thermoplastic polymer coatings.

[0028] In some embodiments, a cathodic protection system disclosed herein may include a sealant on a portion of an anodic coating. For example, a sucker rod may include an anodic coating on a surface of the sucker rod and a sealant on a surface of the anodic coating. A sealant may be organic, inorganic, or a mixture thereof. An organic sealant may include an epoxy, a silicone, and a phenol resin. A sealant may include a moisture cured urethane, a urethane, a clear single component moisture cured urethane, a clear two components (2k) aliphatic polyurethane, and combinations thereof.

[0029] A sealant may advantageously fill the porosity of the anodic coating and may provide physical wear protection of the anodic coating. In some embodiments, a sealant may negate a portion of a cathodic protection provided by an anodic coating until it is worn off of the anodic coating. A sealant may be applied to all or only a portion of the anodic coating contained on a surface of the sucker rod. For example, a sucker rod may have a surface of the anodic coating that is 0.1 % sealed with a sealant, or about 5 % sealed, or about 10 % sealed, or about 15 % sealed, or about 20 % sealed, or about 25 % sealed, about 30 % sealed, or about 35 % sealed, or about 40 % sealed, or about 45 % sealed, about 50 % sealed, or about 55 % sealed, or about 60 % sealed, or about 65 % sealed, or about 70 % sealed, or about 75 % sealed, or about 80 % sealed, or about 85 % sealed, or about 90 % sealed, or about 95 % sealed, or about 100 % sealed, where about includes plus or minus 2.5 %.

[0030] Disclosed in the present application are methods and systems for cathodic protection of a pumping system (e.g., a sucker rod pumping system for an oil and gas well). As shown in FIGURE 1, a sucker rod pumping system 100 includes an anode and a cathode. For example, as discussed below, existing components of the system 100 may be used as the anode and/or the cathode, such that these components perform their traditional functions while providing or benefiting from added protective features (e.g., corrosion protection) provided by existing component of the sucker rod pumping system 100. By way of example, and as discussed below, an anode may be provided with an anodic coating on one or more components of the sucker rod pumping system 100. For example, a surface of a body of a sucker rod string 115 that has one or more sucker rods may have the anodic coating 101 applied thereto ( e.g ., the anodic coating 101 applied on one or more of the sucker rods of the sucker rod string 115). In additional embodiments, other components of the sucker rod pumping system 100 may function as the anode and may include the anodic coating 101.

[0031] The system 100 may include on or more components (e.g., positioned uphole or downhole relative to the anode) that may be cathodes, including, for example, a progressive cavity (PC) pump 125, a tubing string 105, a sucker rod string 115, a polished rod 120, a casing head 180, a tubing head 170, a composite pumping tee (CPT) 110, a surface casing vent line 190, a flow line 140, a flow tee 150, a tubing hanger 160, a polished rod clamp 130, and a surface drive unit 135. In additional embodiments, other components of the sucker rod pumping system 100 may function as the cathode.

[0032] In some embodiments, and as discussed above, the components acting as the anode and cathode may be electrically connected to one another. Such electrical connection may be an electrically conductive connection line that connects the components. As a depicted example in FIG. 1, a simplified connection line 145 is shown extending between the sucker rod string 115 and the progressive cavity pump 125. The simplified connection line 145 may be internal to, external to, and/or integral with the components acting as the anode and cathode and any intervening components.

[0033] By way of example, in use, a positive charge may be applied to anodic coating 101 such that at least a portion of the sucker rod string 115 (e.g., or other selected components) acts as an anode. An opposite charge may be applied to another component or components that are selected as one or more cathodes to be protected (e.g., the progressive cavity pump 125 or other selected components). For example, a negative charge may be applied to the progressive cavity pump 125 such that at least a portion of the progressive cavity pump 125 acts as a cathode.

[0034] A sucker rod rotary pumping system 100 includes a string of tubing 105 containing cylinder and is configured to concentrically contain a sucker rod string 115, a polished rod 120, and a PC pump 125. A system 100 may include a production casing 185 that is located below ground that includes a cylindrical interior cavity that is configured to surround the tubing 105 in a cylindrical manner ( e.g ., cylindrically surround in a lateral or radially direction). A production casing 185 may have a casing head 180 at the top of the production casing 185. A casing head 180 may mechanically connect a production casing 185 to a tubing head assembly 170. Additionally, a casing head 180 may include a surface casing vent line 190 that is mechanically connected to the casing head 180 and extends from the casing head and end above ground. The surface casing vent line 190 permits gas migration from below ground to the surface. Each of a tubing string 105, a sucker rod string 115, a polished rod 120, a production casing 185, a casing head 180, a tubing head assembly 170, and a surface casing vent line 190 may be a cathode that is protected from corrosion through inclusion of an anodic coating surface on a body of a sucker rod string 115.

[0035] As shown in FIGURE 1, a sucker rod pumping system 100 may include a polished rod 120 that connects to a polished rod clamp 130 both located above ground. The bottom of the polished rod 120 may mechanically connect to a top end of a sucker rod string 115. A polished rod 120 may partially protrude above ground from a center of a tubing head assembly 170 and may be partially housed below ground within the interior cavity of the production casing 185. The bottom end of the sucker rod string 115 may mechanically connect to a top end of a progressive cavity pump 125 that is located towards the bottom of the production casing 185. In some embodiments, a progressive cavity pump 125 or plunger pump may be switched out for an electric submersible pump (ESP) artificial lift system.

[0036] The system 100 may include a sucker rod string 115 containing one or more sucker rods. Each sucker rod in the sucker rod string 115 includes a first threaded end, a second threaded end, a solid cylinder, and an anodic coating 101 on a surface of a body of the sucker rod. Application of the anodic coating 101 onto a sucker rod or coiled sucker rod string 115 surface includes a surface preparation and blasting step and a thermal anodic coating spray step. The thermal anodic coating spray step may involve a process where melted or heated anodic coating is sprayed onto the sucker rod surface.

An anodic coating 101 may be applied onto an outside surface of the sucker rod individually or onto a coiled sucker rod string 115. The anodic coating 101 may be applied as thin as 0.20 millimeter (0.008 in.) as thick as 0.51 millimeters (0.020 in.), or it may be applied to other thicknesses according to design needs.

[0037] In some embodiments, the anodic coating 101 may comprise a suitable electrically conductive material, such as, for example, a metallic, semi-metallic, and/or graphitic material. For example, the anodic coating 101 may include, without limitation, copper, tungsten carbide, cobalt, aluminum, magnesium, zinc, iron, platinum, palladium, niobium, graphite, graphene, nichrome, gold, silver, alloys thereof, any suitable metallic material, and/or any other suitable electrically conductive material, without limitation. [0038] The sucker rod pumping system 100 may include other components such as a surface drive unit 135 attached to a tubing head 170 through a composite pumping tee 110. A tubing head 170 may be mechanically connected to a tubing hanger 160. A tubing hanger may include one or more flow lines 140 that may transfer produced oil from the well to any form of known oil collection vessel or oil transport system. A flow line 140 may connect to a composite pumping tee 110 through a flow tee 150.

[0039] The present disclosure relates to methods of cathodic protection of downhole components of a sucker rod pumping system 100. A method includes a step of producing oil using a sucker rod pumping system 100 including an anode and a cathode as described herein where the anode protects the cathode from corrosion.

[0040] In some embodiments, as is shown in FIGURE 2, a pumping system includes a reciprocating sucker rod pumping system 200 including an anodic coating on a surface of a body of a sucker rod string 115. A system 200 includes a prime mover 205 mechanically connected to a beam pumping unit 210 including a horsehead 215. The prime mover 205 provides mechanical energy to the beam pumping unit 210 and the horsehead 215, which translates into a reciprocating motion for down well components through the polished rod 120. The horsehead 215 may be mechanically connected to the polished rod 120 through a carrier bar 220. The polished rod 120 is partially contained above the surface as well as below the surface and transitions through a wellhead 225, which caps the top of the well. System 200 includes a surface casing 230 that concentrically contains a gas flow 235, an oil flow 240, an intermediate casing 245, a production casing 185, a production tubing 105, and a sucker rod string 115. As shown in FIGURE 2, an intermediate casing 245 goes deeper into the ground than the surface casing 230 and concentrically contains a production casing 185. The production casing 185 concentrically contains the sucker rod string 115, a tubing anchor 250, a pump 255 and ends at perforations 260 that may provide effective flow communication between the system 200 and the oil reservoir.

[0041] A reciprocating rod system 200, as shown in FIGURE 2 may include a sucker rod or sucker rod string 115 containing an anodic coating that may provide cathodic protection to one or more of a polished rod 120, a wellhead 225, a surface casing 230, an intermediate casing 245, a production casing 185, a production tubing 105, a tubing anchor 250, and a pump 255. In some embodiments, a system includes a cathode including the polished rod 120, the wellhead 225, the surface casing 230, the intermediate casing 245, the production casing 185, the production tubing 105, the tubing anchor 250, and the pump 255.

[0042] The corrosion and wear associated with downhole systems reduces the lifespan of sucker rod pump systems. Embodiments of disclosed systems and methods for cathodic protection of sucker rod pump systems may relatively increase the lifespan of and therefore reduces operating costs of using the sucker rod pump systems to produce oil from an oil well.

[0043] As is shown in Table 1 below, a disclosed anodic coating outperforms comparative thermosetting fusion bonded epoxy (FBE) and polyethylene coatings. Even when using a thinner anodic coating ( e.g 10-20 mils), it provides for both barrier and cathodic protection whereas FBE and polyethylene coatings only provide barrier protection. Anodic coatings are generally impermeable to fluids whereas FBE and polyethylene coatings are semi-permeable. Being impermeable to fluids advantageously minimizes or prevents fluid ingress between the coating and the sucker rod metal substrate since entrapped fluid may corrode the metal substrate and lead to a detachment of the coating from the surface of the metal substrate. Anodic coatings as disclosed herein may have virtually or substantially no limit to clamping pressure of the rod injector used to either deploy or retrieve a coiled sucker rod, whereas FBE and polyethylene coatings both have limitations. Additionally, anodic coatings generally have no depth or handling equipment limitations whereas FBE and polyethylene coatings both do. As is shown in Table 1, the response to mechanical damage of an anodic coating is to smear, whereas FBE gouges off and polyethylene coatings peel off. Anodic coatings have excellent adhesion, whereas FBE has good and polyethylene coatings have fair. Additionally, anodic coatings require no special coating disposal. Also, anodic coated sucker rods may operate at temperatures of over 200 ^° C where FBE is limited to about 90 ^° C.

Table 1. Comparison of Anodic Coatings to FBE and Polyethylene Coating

[0044] FIGURE 3 illustrates a cross-sectional view of a coating on at least one component of an oil and gas well ( e.g ., sucker rod 300). As shown in FIGETRE 3, the coating 302 may be applied about a circumference of the sucker rod 300 (e.g., an entire circumference). [0045] As also depicted in an idealized schematic form, a conductive element 304 may couple the sucker rod 300 to another component 306 of the oil and gas well. As above, the conductive element 304 may be internal to, external to, and/or integral with the sucker rod 300 and the another component 306 acting as the anode and cathode, respectively, and any intervening components.

[0046] FIGURE 4 illustrates a cross-sectional view of a coating on at least one component of an oil and gas well ( e.g ., sucker rod 400). As shown in FIGURE 4, the coating 402 may be applied at selected locations about a circumference of the sucker rod 400. For example, as discussed above, the coating 402 may applied as one or more longitudinal strips 404 extending along a length of the sucker rod 400 (e.g., along a longitudinal axis of the sucker rod 400). In some embodiments, the coating 402 may be applied on sucker rod 400 as two or more longitudinal strips 404 (e.g., two, three, four, or more) that are positioned on opposing about the sucker rod 400.

[0047] As also depicted in an idealized schematic form, a conductive element 406 may couple the sucker rod 400 to another component 408 of the oil and gas well. As above, the conductive element 406 may be internal to, external to, and/or integral with the sucker rod 400 and the another component 408 acting as the anode and cathode, respectively, and any intervening components.

[0048] While various aspects and embodiments have been disclosed herein, other aspects and embodiments are contemplated. The various aspects and embodiments disclosed herein are for purposes of illustration and are not intended to be limiting.

[0049] Terms of degree (e.g., “about,” “substantially,” “generally,” etc.) indicate structurally or functionally insignificant variations. In an example, when the term of degree is included with a term indicating quantity, the term of degree is interpreted to mean ± 10%, ±5%, or +2% of the term indicating quantity. In an example, when the term of degree is used to modify a shape, the term of degree indicates that the shape being modified by the term of degree has the appearance of the disclosed shape. For instance, the term of degree may be used to indicate that the shape may have rounded corners instead of sharp corners, curved edges instead of straight edges, one or more protrusions extending therefrom, is oblong, is the same as the disclosed shape, etc.