PAD PLUNGER

Description

PRIORITY CLAIM

This application claims priority to provisional patent application Ser. No. 63/643,593 filed May 7, 2024, which is fully incorporated herein by reference.

TECHNICAL FIELD

Embodiments of the subject matter disclosed herein relate to an improved pad plunger for use in oil and gas wells.

DISCUSSION OF THE BACKGROUND

As those skilled in the art will appreciate, a pad plunger is a type of artificial lift device designed to remove accumulated liquids from an oil or gas well and improve production efficiency. The pad plunger consists of a cylindrical body equipped with extendable pads that press against the tubing walls, typically creating a better seal than conventional plungers. The purpose of the pads is to reduce gas bypass, ensuring that the maximum amount of liquid is lifted to the surface with each plunger cycle.

The functionality of a pad plunger depends on cyclical pressure changes within the wellbore. As the plunger descends, it reaches the bottom of the well, where it rests until sufficient gas pressure builds up beneath it. When this pressure reaches a critical threshold, it forces the plunger upwards, carrying liquid to the surface. The cycle then repeats as the plunger returns to the bottom.

Springs are used to keep the pad plunger's pads extended against the tubing wall, which is a crucial aspect of the pad plunger's operation. These springs apply outward force to ensure the pads maintain contact with the tubing, substantially preventing gas from escaping around the plunger. Without this sealing effect, the plunger would be less effective at lifting liquids. The springs also allow the pads to adapt to variations in the tubing's inner diameter since, over time, well tubing may develop irregularities due to deposits, corrosion, or wear. The spring-loaded pads compensate for these inconsistencies, maintaining a substantially reliable seal even in less-than-perfect conditions.

During the upward movement of the plunger, the pads remain pressed against the tubing walls, ensuring that gas pressure is efficiently utilized to push liquid above the plunger to the surface. This seal enhances the lifting capability of the plunger, maximizing the volume of liquid removed with each plunger cycle. When the plunger reaches the surface, it typically enters a lubricator, where the accumulated liquid is discharged. Once the pressure equalizes (which can take place by shutting in the well), the plunger begins its descent back to the bottom of the well. The springs also play an important role during this phase, as they allow the pads to retract slightly, minimizing friction and reducing wear on both the tubing and the plunger itself.

Compared to other types of plungers, a pad plunger can offer a more effective seal, particularly in wells with low gas flow rates. Traditional solid-body plungers rely on metal-to-metal contact with the tubing, which can result in gas bypass and reduced efficiency. The extendable pads of a pad plunger mitigate this issue by providing a flexible yet effective sealing mechanism.

For example, ball-and-sleeve plungers operate using a different principle, allowing gas to pass through the plunger during descent and sealing shut during ascent. While useful in many applications, ball-and-sleeve plungers typically do not provide as strong of a seal as pad plungers, especially in wells where gas bypass is a concern. This makes pad plungers a better option in many cases.

Brush plungers, which use bristles to create a seal, are another alternative. However, the bristles on these plungers wear out over time, thereby reducing their sealing ability. In contrast, the spring-loaded pads in a pad plunger maintain their performance longer and are more resistant to mechanical degradation.

Flex plungers are designed to navigate wells with extreme deviations or bends, thereby making them suitable for horizontal wells. While flex plungers offer great flexibility, they do not provide as strong of a seal as pad plungers in straight or slightly deviated wells. The ability of pad plungers to maintain a consistent seal has traditionally given them an advantage in vertical or slightly inclined wells.

Pad plungers also can be a better choice than many other artificial lift devices, such as gas lift systems. Gas lift requires the continuous injection of gas into the well to assist with liquid removal, which can be costly and operationally complex. A pad plunger, on the other hand, utilizes the well's natural gas pressure, eliminating the need for additional energy input.

Compared to rod pumps, which use mechanical motion to lift fluids, pad plungers offer a simpler and more cost-effective solution. Rod pumps require downhole and surface equipment, including a pumpjack, which increases capital and maintenance costs. Pad plungers operate with minimal surface equipment, making them a more economical choice.

Electrical submersible pumps (ESPs) are another common artificial lift method, but ESPs require electricity and are prone to failures in wells with high gas content. Pad plungers, being purely mechanical, are not affected by electrical issues and can operate in a wider range of well conditions. Likewise, jet pumps, which use high-pressure fluid to lift liquids, are effective but require surface pumping equipment and additional operational costs. Pad plungers, in contrast, function using the natural energy of the well, making them a more energy-efficient and low-maintenance option.

One of the key advantages of pad plungers is their ability to adapt to varying well conditions. Because the pads adjust dynamically to tubing irregularities, they remain effective even as the well ages. This adaptability makes them a long-term solution for maintaining production. Pad plungers also have a lower environmental impact compared to other artificial lift methods. Since they do not require external power sources or injected gas, they help reduce the carbon footprint of oil and gas operations. This aligns with industry efforts to improve sustainability.

Operational flexibility is another benefit of pad plungers. They can be used in both high- and low-pressure wells, and their performance can be optimized by adjusting cycle times. Operators can fine-tune their settings based on real-time well conditions, thereby improving overall efficiency.

The durability of pad plungers is another reason they may be preferred in many applications. The materials used in their construction, such as hardened steel and corrosion-resistant alloys, ensure that they can withstand the harsh conditions of downhole environments. Moreover, regular maintenance of pad plungers is relatively simple. Unlike ESPs or rod pumps, which require complex servicing, pad plungers can be easily inspected and replaced if necessary. This reduces downtime and operational costs, often making them a practical choice for long-term use.

Pad plungers also enhance well safety by reducing the need for manual intervention. Since they operate automatically based on well pressure, they require less frequent operator interaction, thereby reducing the risk of accidents. Operators can further optimize pad plunger performance by using real-time monitoring systems. Pressure sensors and flow meters help track plunger cycles and identify inefficiencies, thereby allowing for proactive maintenance and adjustments.

Despite the above-described utility and advantages of pad plungers, the present inventors have observed a drawback to their use in severely deviated wells, for example, wells that have one or more substantially vertical components and one or more substantially horizontal components. (Those skilled in the art will appreciate that the invention is likewise applicable to wells that are not as severely deviated.) In these wells it has been observed that the pad plunger may not fully descend to the bottom (or fully desired depth) of the well. One reason for this is that at least the tail end portion of the plunger tends to drag or rub on the wellbore wall as the plunger descends and traverses a deviation in the well. This rubbing/dragging effect can slow the plunger's descent to such a degree that it may not fully descend to the bottom (or fully desired depth) of the well, thereby preventing the plunger from removing liquids from the well that are situated below the plunger's resting/stopping place.

As those skilled in the art will appreciate from the description below, the present inventors have discovered a new and non-obvious method and apparatus for overcoming this deficiency in today's pad plungers.

BRIEF DESCRIPTION OF THE DRAWINGS

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:

FIG. 1 is a side view of a pad plunger having varied spring forces.

FIG. 2 is a cross section of FIG. 1.

FIG. 3 is a perspective view of FIG. 1.

FIG. 4 is a partial cross section of an embodiment of FIG. 1 showing thicker wire springs on the back pads with a higher spring rate than the springs on the front pads, and wherein the spring pockets for the front and back pads are the same depth.

FIG. 5 is a partial cross section of an embodiment of FIG. 1 showing spring pockets having a shallower depth for the back pads than for the front pads.

FIG. 6 is a partial cross section of an embodiment of FIG. 1 showing thicker wire springs on the back pads with a higher spring rate than the springs on the front pads, and wherein the spring pockets for the front pads are deeper than the spring pockets for the back pads.

DETAILED DESCRIPTION

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.

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.

The present exemplary embodiments describe an improved pad plunger for use in oil and gas wells. As explained above, pad plungers are well-known to those skilled in the art. An exemplary pad plunger is described in U.S. Pat. No. 9,932,805, which is hereby incorporated by reference. While the present invention is an improvement on the pad plungers disclosed in that patent, those skilled in the art will appreciate that the present invention is not limited to the pad plungers disclosed therein. Indeed, those skilled in the art will appreciate from this disclosure that other embodiments are contemplated. For example, FIG. 1 illustrates a side view of an exemplary pad plunger 10 of the present invention. FIG. 3 is a perspective view of pad plunger 10 shown in FIG. 1. In this embodiment, of which others are possible, pad plunger 10 may have one or more pads 11, a first or back end 12, and a second or front end 13. The terms “back” end and “front” end are relative and could equally be considered “top” end and “bottom” end, respectively. Specifically, the “back end” or “top end” 12 of plunger 10 is used herein to refer to the orientation of the plunger as it descends in a well. In that case, “back end” or “top end” 12 will be closest to the top or surface of the well as the plunger descends in a vertical portion of the well. Likewise, the “front end” or “bottom end” 13 of plunger 10 also is used herein to refer to the orientation of the plunger as it descends in a well. In that case, “front end” or “bottom end” 13 will be closest to the bottom of the well as the plunger descends in a vertical portion of the well.

Pad plunger 10 also may include a fish-neck at or near its back/top end, which those skilled in the art will appreciate can be used to retrieve the plunger from a well in a variety of circumstances. Pad plunger 10 also may include grooves 15, which can be cut or otherwise formed in the front/bottom end of the plunger to encourage the plunger to rotate or spin as it descends in a well, thereby encouraging more uniform wear on the plunger. As those skilled in the art will appreciate, the body of plunger 10 may be formed from a single or multiple units, as better shown in FIG. 2.

FIG. 2 is a cross section of FIG. 1. FIG. 2 better illustrates some of the operational nature of pad plunger 10. Specifically, FIG. 2 shows four separate pads 11, where each pad is biased by two springs 16. It should be noted that the present invention is not limited to a pad plunger having any particular number of pads or any particular number of springs that bias each pad. The embodiments identified in the Figures are merely illustrative. Springs 16 bias pads 11 outward, i.e., away from a centerline (running from the back/top end to the front/bottom end) of plunger 10 and toward the walls of the wellbore in which the plunger is operating. As explained above, these spring/pad combinations allow the pads to form a seal between the pads and the walls of the wellbore, while also allowing the pads to deform (by moving inward and outward relative to the plunger's centerline) to accommodate irregularities in the inside diameter of the wellbore.

The present inventors have noted that as a plunger descends or ascends in a deviated portion of a wellbore, one or more ends or portions of the plunger body (as opposed to only the pads) may scrape along the walls of the wellbore more than otherwise happens when the plunger descends or ascends in a more vertical portion of the well. This scraping action is more prevalent (or worsens) as the rate of deviation increases. As explained above, this can reduce the velocity of the plunger (even causing the plunger to not reach the bottom or intended depth in the wellbore) and can cause undue wear on the plunger itself. As described in more detail below, the present inventors have discovered that this scraping and its deleterious effects can at least be reduced by varying the biasing on one or more pads on the pad plunger.

In that regard, FIG. 4 is a partial cross section of an embodiment of FIG. 1 showing some pads on the plunger being biased differently than other pads on the plunger. This unbalanced biasing can be accomplished, for example, by using a biasing force such as springs with different ratings. As those skilled in the art will appreciate, springs are rated based on several key parameters that define their strength, resistance, or force characteristics. The primary factors used to rate a spring include spring rate (stiffness), load capacity, free length, solid height, and material properties. These factors—as described below in more detail—determine how a spring behaves under compression, extension, or torsion.

1. Spring Rate (k) or Stiffness:

The most important measure of a spring's strength is its spring rate, denoted as k, which is defined as the force required to compress or extend the spring by a unit of length. It is typically expressed in units such as pounds per inch (lbf/in) or newtons per millimeter (N/mm). The equation for spring rate in a linear compression or extension spring is:

k=F/x

• • where:
    • k=spring rate (force per unit deflection)
    • F=applied force
    • x=displacement (compression or extension)

2. Load Capacity:

This is the maximum force a spring can handle before it becomes permanently deformed. A spring's load capacity depends on its material, wire diameter, coil count, and overall design.

3. Free Length and Solid Height:

• • Free length is the length of the spring when no force is applied.
  • Solid height is the compressed length when all coils are fully touching. These measurements help determine how much the spring can compress before reaching a solid state.

4. Hooke's Law Compliance:

Most springs follow Hooke's Law, which states that force is proportional to displacement (F=kx), meaning the stiffness remains constant until the elastic limit is reached.

5. Spring Constant Variability:

While many springs have a linear force-displacement relationship, some are progressive-rate springs, meaning the stiffness changes as they compress (e.g., in automotive suspension springs).

6. Material and Wire Diameter:

The material type (e.g., steel, stainless steel, titanium) and wire diameter affect the spring's resistance to deformation. A thicker wire increases stiffness.

7. Coil Count and Diameter:

The number of active coils and the coil diameter determine the amount of deflection a spring can handle. More coils or a larger diameter typically result in lower stiffness.

8. Preload and Initial Tension:

Some springs, especially extension springs, have a built-in preload (initial tension) that must be overcome before any movement occurs.

In the particular embodiment shown in FIG. 4, the first set of springs 16 on the back/top end 12 of plunger 10 are shown to be heavier/thicker than the second set of springs 16 on the front/bottom end 13 of plunger 10. As explained above, this increase in diameter of the first set of springs relative to the second set of springs is one way of giving the first set of springs a higher/greater spring rate than the second set of springs, which results in more force being required to compress the pads 11 associated with the first set of springs than to compress the pads 11 associated with the second set of springs. This also assists in keeping (or reducing) one or more regions of plunger 10 between fish-neck 14 and the pads 11 associated with the first set of springs from scraping against the walls of the wellbore when the plunger descends or ascends in the wellbore. Put differently, the more easily the pads 11 associated with the first set of springs compress, the more easily (or likely) one or more regions of plunger 10 between fish-neck 14 and the pads 11 associated with the first set of springs will scrape against the walls of the wellbore, especially when the plunger traverses a deviated section of the wellbore. The same principle is applicable to the pads 11 associated with the second set of springs, i.e., increasing the rate of the second set of springs keeps (or reduces) one or more regions of plunger 10 between front/bottom end 13 and the pads 11 associated with the second set of springs from scraping against the walls of the wellbore when the plunger descends or ascends in the wellbore, especially when the plunger traverses a deviated section of the wellbore. As shown in FIGS. 4-6, a preferred embodiment of the invention is to set at least one or more of the first set of springs at higher/greater spring rate than the second set of springs because it is believed that attempting to minimize scraping in the region of the back/top end of the plunger optimizes performance.

This unbalanced biasing of the plunger's pads also can be accomplished, for example, by using spring pockets of different depths instead of varying the spring rate of the springs. Specifically, as best shown in FIGS. 4-6, the end of each spring sits in a pocket, where one end of each spring sits in a pocket on a pad and the other end of each spring sits in a pocket on the plunger body. While FIG. 4 shows all the spring pockets on the plunger body being equal depth and all the spring pockets on the pads being equal depth, FIG. 5 shows the spring pockets on the pads being equal depth but the spring pockets on the plunger body associated with the first set of springs being shallower than the spring pockets on the plunger body associated with the second set of springs. Assuming the same spring rate is used for each spring and each spring is the same length (as intended in FIG. 5), the first set of springs will already be compressed more than the second set of springs due to the reduced depth of the spring pockets on the plunger body associated with the first set of springs relative to the greater depth of the spring pockets on the plunger body associated with the second set of springs. (Note that the same effect could be accomplished by varying the depth of the pockets on the pad or a combination of the pocket depth on both the pad and the plunger body.)

As explained above in connection with the formula F=kx, the initial force required to compress the pad at the back/top end of the plunger shown in FIG. 5 will be greater than the initial force required to compress the pad at the front/bottom end of the plunger. This results in a plunger operation like that described above in connection with FIG. 4, i.e., it assists in keeping (or reducing) one or more regions of plunger 10 between fish-neck 14 and the pads 11 associated with the first set of springs from scraping against the walls of the wellbore when the plunger descends or ascends in the wellbore, particularly deviated sections of the wellbore. It should be appreciated that the depth of the spring pockets associated with the second set of springs could be reduced relative to the depth of the spring pockets associated with the first set of spring to assist in keeping (or reducing) one or more regions of plunger 10 between front/bottom end 13 and the pads 11 associated with the second set of springs from scraping against the walls of the wellbore when the plunger descends or ascends in the wellbore, particularly deviated sections of the wellbore.

As shown in FIG. 6, combinations of the teaching of FIGS. 4-5 are possible. Specifically, FIG. 6 shows the first set of springs having a higher spring rate than the second set of springs (by virtue of being thicker) and associated with shallower spring pockets on the plunger body. In view of the present disclosure, those skilled in the art should appreciate that combinations of the above teachings are contemplated. For example, any combination of spring rates and spring pocket depths can be used to vary the biasing of any one or more of the pads on a pad plunger. Likewise, while the Figures show preferred embodiments using two springs and two pockets for each pad, the same principles described herein can be applied to an embodiment that uses a single pocket and a single spring (or other biasing force) for each pad. It should also be noted that it is intended that a “pocket” having zero depth is still a pocket, since one or more of the biasing forces could be installed between the pad and body of the plunger without an actual indentation or receiving area for the biasing force.

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.

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.

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