US 20030155129 A1
A plunger for use in downhole tubulars in wells which produce fluids and/or gases under variable pressure. The plunger is slidingly engageable within the tubulars and capable of movement up and down the tubulars, and has a jacket comprised of segments mounted about a core which have sealing, holding, and lifting capabilities. An inner turbulent or labyrinth-type seal is accomplished by circumferential grooves on the core and/or fingers which project inwardly from the underside of the segments. When the pressure inside the tubulars above the plunger is reduced, the plunger and fluids move upwardly to the surface.
1. A plunger for use in a gas/fluid lift system in downhole tubulars in wells producing fluids and/or gases under variable pressures, comprising:
a body slidingly engageable within the tubulars and capable of movement up and down said tubulars;
said body having a top end and a bottom end;
an inner core within the body for internal sealing;
a flexible jacket having plurality of segments mounted about said core, each of said segments having a convex outer surface and an inner surface, first and second sides, and top and bottom ends;
said jacket having an inner surface providing an internal seal, and an outer surface being radially expandable to provide an external seal against the interior of said tubulars;
a flow path for fluids and/or gases between said core and the inner surface of said jacket;
wherein each of said internal and external seals retards the upward flow of fluids and/or gases which thereby increases pressure below the plunger to thereby move the plunger and accumulated well fluids upwardly to the surface when the pressure inside the tubulars above the plunger is reduced.
2. The plunger of
3. The plunger of
4. The plunger of
5. The plunger of
6. The plunger of
7. The plunger of
8. The plunger of
9. The plunger of
10. The plunger of
11. The plunger of
12. The plunger of
13. The plunger of
14. The plunger of
15. The plunger of
16. The plunger of
17. The plunger of
18. The plunger of
19. The plunger of
20. The plunger of
21. The plunger of
22. The plunger of
23. The plunger of
24. The plunger of
25. The plunger of
26. The plunger of
27. A plunger for use in a gas/fluid lift system in downhole tubulars in wells producing fluids and/or gases under variable pressures, comprising:
a body slidingly engageable within the tubulars and capable of movement up and down said tubulars;
said body having a top end and a bottom end;
an inner core within the body for internal sealing;
an external sealing means having an outside surface and an underside surface mounted about said core radially expandable to seal against the interior of said tubulars;
a flow path for fluids and/or gases between said core and the underside of said external sealing means;
an internal sealing means disposed between or on the core and/or the underside of said external sealing means;
said internal and external sealing means retarding the upward flow of fluids and/or gases which thereby increases pressure below the plunger to thereby move the plunger and accumulated well fluids upwardly to the surface when the pressure inside the tubulars above the plunger is reduced.
28. The plunger of
29. The plunger of
30. The plunger of
31. The plunger of
32. The plunger of
33. The plunger of
34. The plunger of
35. The plunger of
36. The plunger of
37. The plunger of
38. The plunger of
39. The plunger of
40. The plunger of
41. The plunger of
42. The plunger of
43. The plunger of
44. The plunger of
45. A method of lifting well fluids and/or gases from a subterranean reservoir to the surface in tubulars in wells comprising: placing a plunger having an inner core and an external sealing means mounted about said core radially expandable to provide an external seal against the interior of said tubulars and an internal sealing means disposed between or on the core and/or beneath said external sealing means which comprises at least one rigid finger and at least one circumferential groove disposed between or on said core and the external sealing means inside said tubulars to retard the upward flow of fluids and/or gases, allowing said plunger to descend or gravitate to the bottom of the well or a well stop, using internal sealing means to create a tortuous path of flow between said core and said external sealing means thereby effecting a turbulent inner seal which thereby pushes the external sealing means outwardly to cause an external seal with the tubulars, allowing the pressure to build up in the well to predetermined level, opening a valve connected to the tubulars which decreases the pressure inside the tubulars, thereby elevating the plunger and the accumulated well fluids to the surface.
 1. Field of the Invention
 The present invention relates to improvements in plungers used in a gas/fluid lift system in wells producing both fluids and gases, such as petroleum and natural gas, under variable pressure to facilitate the lifting of fluids from a subterranean reservoir to the surface through a well conduit or tubulars. Plungers of this type are designed to minimize the downward flow of fluids as well as the upward flow of gases beneath the plunger as the plunger travels upwardly to the surface. Tubulars include, but are not limited to, a variety of tubes and tubular members, such as cement casings, conduits, tubing and tubing strings which are placed in the well conduit, and may also be referred to as the production string. More specifically, the gas plunger invention concerns improvements in the internal and external sealing of the apparatus. The external sealing means or apparatus is typically comprised of a plurality of segments, which collectively forms a jacket assembly that sealingly and slidingly engages the well tubulars. A turbulent inner seal is accomplished by sealing means such as circumferential grooves on the inner core and/or fingers which project inwardly from the segments toward the inner core which may or may not be grooved. Alternatively, the inner surface of the segments may have furrows and there may be raised bands on the core which also effects a turbulent inner seal. The circumferential grooves and/or fingers, or the bands and/or furrows, provide a tortuous path of flow that deflects escaping gas streams and/or fluids, promotes turbulence in the manner of a labyrinth seal, and has gas sealing capabilities.
 Another further and alternative improvement concerns a simplified sucker rod and valve-like assembly used to regulate and restrict the flow of fluids and gases through the internal passage of the plunger which allows such plungers to descend to the well bottom more rapidly than plungers without internal passages so that flow occurs only during the downward cycle or descent of the gas plunger.
 2. Description of the Prior Art
 Differential gas pressure operated pistons, also known as plungers, have been used in producing subterranean wells where the natural well pressure is insufficient to produce a free flow of gas, and especially fluids, to the well surface. A plunger lift system typically includes tubulars placed inside the well conduit, which extend from the reservoir(s) of the well to the surface. The tubulars have a well valve and lubricator at the top and a tubing stop and often a bumper spring or other type of spring assembly at the bottom. The cylindrical plunger typically travels between the bottom well stop and the top of the tubulars. The well is shut in for a selected time period which allows pressures to build up, then the well is opened for a selected period of time. When the well valve is opened, the plunger is able to move up the tubulars, pushing a liquid slug to the well surface. When the well valve is later closed, the plunger, aided by gravity, falls downwardly to the bottom of the tubulars. Typically, the open and closed times for the well valve are managed by a programmable electronic controller.
 When the plunger is functioning properly, fluids accumulate and stay above the plunger and pressurized gases and/or fluids below the plunger are blocked from flowing up, around, and through the plunger. As a result, the plunger and accumulated fluids are pushed upwardly. The prior art devices use a variety of external, and sometimes internal, sealing elements which allow the plungers to block the upward flow of gases and slidingly and sealably engage the tubulars, which accomplishes the lifting of fluids to the surface depending upon the variable well pressures. Examples of prior art gas operated plungers include those disclosed in U.S. Pat. Nos. 5,427,504 and 6,045,335 (hereinafter the '504 and '335 patents). The prior art plunger of the '504 patent features mechanical sealing which is accomplished by segments that are biased outwardly against the tubulars by springs. The build up of internal pressure is accomplished by a flexible, elastomeric seal placed beneath the segments. The outer sealing assembly is comprised of a plurality of segments or pads. However because such resilient compounds like rubber do not last for extended periods of time in the harsh well environment, problems with inner sealing develop and the plunger must be taken out of service for time-consuming seal replacements. Further, if the inner spring member which assists in biasing of the segments becomes detached or lost, sealing problems could result.
 In contrast, the prior art plunger of the '335 patent has upper and lower sets of segments whose sides are juxtaposed with respect to each other and collectively work together. The segments are biased outwardly against the tubulars by springs and the build up of internal pressure. The sealing element therein consists of a rigid inner ring member surrounding the intermediate portion of the piston body, which is positioned between the piston body and between the inner surfaces of each set of cylindrical segments, which cooperate to slidingly engage the rigid ring member and create an inner seal. However, the segments of this design can be prone to leakage.
 Other prior art plungers which have externally grooved surfaces and which lack outer sealing elements or segments are, for example, disclosed in U.S. Pat. Nos. 4,410,300 and 6,200,103. These external grooves deflect the escaping gas streams and promote turbulence in the manner of a labyrinth seal and have gas sealing capability. However, the grooves are prone to structural failure due to external wear and erosion due to contact with the tubulars, and these plungers can also become jammed within the tubulars because these types of plungers do not have the capability of contracting radially inward, as do the plungers with cooperating mechanical sealing segments. The improved plunger design incorporates the concept of a labyrinth seal in its internal sealing elements.
 Other examples of prior art gas operated plungers include those with internal bores or passages to speed the descent of the plungers. These plungers have a variety of valve closure members which seal the internal bore, and the prior art valve closure members are often spring loaded and work in conjunction with long rods which typically extend downwardly through the bore to unseat the valve closure member, as disclosed in the '504 and '335 patents. The design of the piston disclosed in the U.S. Pat. No. 6,045,335 includes a complicated valve mechanism which requires a unit to capture the piston at the surface and requires a long rod which moves downwardly through the plunger bore to disengage and unseat the valve closure member, and to open the internal valve. However, this rod used to reopen the valve assembly is prone to damage and bending if the rod and plunger bore become even partially unaligned, requiring expensive and time-consuming repair or replacement. Additionally, this type of plunger also requires expensive and customized installation of equipment at the well surface such as spring loaded stops to accomplish disengagement of the valve closure member. In contrast, the plunger of the '504 patent has a bypass valve with a ball-shaped closure member and a spring loaded rod activator, or shock spring, which pushes the ball up into the valve seat to seal off the flow path. The spring loaded rod activator opens the valve after the plunger reaches the lubricator at the top of the well and the pressures above and below the plunger are equalized.
 In contrast, the improved stopper assembly which is housed in a chamber is typically located in a modified end cap and seals off the inner flow passage in a simplified manner. The stopper stem and stopper head is pushed up into the chamber when the plunger bottom contacts the well stop means, and the stopper is held up against the opening of the flow passage by the fluid and/or gas pressure below the plunger. This simplified and improved design dispenses with the need for complicated moving parts which to actuate the closure means, and eliminates the need for expensive equipment at the well head which is used to unseat the closure means.
 The improved plunger inventions seek to dispense with the problems of the prior art such as erosion, leakage, erratic or unsafe operation, malfunctions, and costly replacements or repairs. Many other objects and advantages of the inventions, besides substantially trouble free operation, will be apparent from reading the description which follows in conjunction with the accompanying drawings.
 The present invention provides a plunger for use in a gas/fluid lift system in tubulars in wells producing both fluids and gases under variable pressure. The plunger assists with the build up of pressure between the subterranean reservoir and the surface by having an inner seal and an external sliding and variable holding seal with adjacent well tubulars. The inner and external seals restrict the upward flow of the fluids and/or gases. This causes an increase in the well pressure below the plunger and facilitates the upward lifting of the plunger and fluids from the reservoir to the surface when pressure is reduced above the plunger, such as at the well head, The improved plunger comprises a body which is slidingly engageable and which gravitates within the tubulars. The plunger body has an external sealing means such as a plurality of segments which are mounted around a core, also known as a mandrel, and which collectively form a jacket. The segments, collectively the jacket assembly, are slidingly and sealingly engageable with the insides of the well tubulars, based upon the pressure effected between the inner surface, or inside, of the jacket and the core. The jacket has the largest diameter of the plunger when the segments are in an expanded radial position. The segments have a convex outer surface and typically have a concave inner surface. However, the core of the plunger could be square, triangular, or of another geometric shape, in which case the inner surfaces of the segments could be flat, or of any other corresponding geometric shape.
 In a preferred embodiment of the plunger, there is also an inner sealing means such as at least one rigid finger which projects radially inward from the underside of each segment toward the core, with the fingers of the adjacent segments collectively cooperating to encircle the core. Preferably, there are a plurality of fingers on the undersides of each segment. The fingers are normally separated from the core especially when the segments, collectively the jacket, are pushed radially outward. This creates a path of flow for gases and/or liquids and the fingers collectively create a tortuous path of flow between the core and the segment undersides and effect a turbulent inner seal. When the segments making up the jacket are pushed to their most radially inward position, the fingers touch the core and cause a complete inner seal. In another embodiment of the plunger, the core has at least one circumferential groove on its surface, and more preferably a plurality of grooves. This also creates a tortuous path of flow between the core and the jacket underside and effects an inner seal. In another embodiment, the plunger has both grooves and fingers, and the fingers are correspondingly located to fit into the grooved portions of the core. This design creates an even more tortuous path of flow for fluids and gases which effects an inner seal and creates an increased surface area between the segments and core. The increased surface area also has the effect of increasing the internal plunger pressure, i.e., the pressure between the core and the jacket assembly and energizes the segments, pushing the segments radially outward toward the well tubulars. This preferred design also prevents detachment and/or loss of the segments if the retainer rings, explained below, fail because the segments will be held in place by the finger-groove interface and by the outer well tubulars. This design provides for increased functionality and seeks to minimize expensive and time consuming fishing operations to retrieve dislocated parts.
 An alternate embodiment also has at least one biasing means, which is typically a spring, between the underside of each segment and the core to outwardly bias each segment and to achieve inward and outward radial rebounding of the segments from the inner core. The preferred embodiment also has recessed spaces, or blind holes, in the core or core grooves and/or the fingers which hold the biasing means in place between the core and segments and prevent displacement and loss of the biasing means. The preferred embodiment typically also has retaining means such as retaining rings which limit the outward radial movement of the segments/jacket assembly. In plungers with both fingers and grooves, at least one of the outside edges of the grooves will be angularly reduced to allow installation of segments with projecting fingers into the grooves of the core and allows the end of the segments to be installed underneath the retaining rings.
 In yet another embodiment of the invention, the plunger has an internal passage which extends partway through the body, or through the entire axis of the plunger, to facilitate more rapid descent of the plunger to the bottom of the well or the well stop means. These plungers also have a top end and a bottom end with at least one opening at or near the top and the bottom end and may have a plurality of radial ports which connect to the bore to increase the flow rate and to facilitate even more rapid descent of the plunger. The preferred embodiment has a plurality of radial ports near the top end and bottom end. These plungers further have a chamber in a modified end cap near the bottom end which houses a closure means such as a plunger stopper. The chamber connects to the internal passage at the roof and connects to the stem bore in the floor of the chamber. The plunger stopper has a top end which has a shape similar to that of the roof, or upper chamber area, and has a stem attached to the bottom end which extends downward through and protrudes outwardly from a bore opening in the bottom end. When the stem engages the bottom well stop means upon descent, the closure means such as a stopper, is pushed upwardly against the roof of the chamber, thereby sealing off the inner flow passage and restricting the upward flow of fluids and/or gases in order to build up pressure below the plunger. The improved design of this closure means, or stopper, operates without springs or catches, yet still holds the stopper against the roof of the chamber. It also does not use long sucker rod, which are prone to bending, to unseat the closure means. Instead, the pressure build-up below the plunger keeps the plunger stopper engaged against the roof of the chamber. The simplified bore sealing means also reduces the amount of time needed for costly and time-consuming repairs and replacements and dispenses with the need for expensive and customized devices at the surface that unseat the prior art closure valves.
 The preferred embodiments of this invention may also have the previously described advantages of the rigid fingers, the grooved core, the spring recesses, and the reduced edge of the core groove. In another preferred embodiment of the invention, the top end of the closure means, such as the plunger stopper, also has a stem which is pushed upward into the inner passage above the chamber roof to further seal off the inner passage.
 Details of this invention are described in connection with the accompanying drawings that bear similar reference numerals in which:
FIG. 1 is a schematic representation of an operating well and production of the well by utilizing a gas operated plunger according to an embodiment of the invention;
FIG. 2 is a longitudinal, external view, of a gas operated plunger;
FIG. 3 is an upper end view of the four segments of the embodiment of FIG. 2;
FIG. 4 is an inner, perspective view of the grooved core and jacket assembly of the segments of FIGS. 2-3, with one of the segments removed;
FIG. 5 is a longitudinal view of two of the four cooperating segments which form the jacket assembly for use with the preferred embodiment of FIG. 18;
FIG. 6 is a view of the upper end of the four segments of FIG. 5;
FIG. 7 is an inner, perspective view of one of the segments of FIGS. 5-6;
FIG. 8 is an outer perspective view of one of the segments of FIGS. 5-6;
FIG. 9 is an inner planar, or flattened, perspective view of one of the segments of FIGS. 5-7;
FIG. 10 is an outer planar, or flattened, perspective view of one of the segments of FIGS. 5-6, 8;
FIG. 11 is a cross-sectional view of the segments of FIGS. 6, 9, taken across lines D-D of FIG. 9;
FIG. 12 is a cross-sectional view of the segments of FIGS. 6, 9, taken across lines A-A of FIG. 9;
FIG. 13 is a cross-sectional view of the segments of FIGS. 8, 10, taken across lines C-C of FIG. 10;
FIG. 14 is a cross-sectional view of the four segments of FIGS. 5, 6, taken across lines B-B of FIG. 10;
FIG. 15 is a cross-sectional view of the segments of FIGS. 8, 10, taken across lines B-B of FIG. 10;
FIG. 16 is a detailed drawing, partially in section, illustrating the biasing means of the preferred embodiment of FIG. 18, and the sectional view of the grooves and segments of FIGS. 9, 12;
FIG. 17 is a detailed drawing, partially in section, illustrating the flow in the area between the segments and grooves in FIG. 16 of the preferred embodiment of FIG. 18;
FIG. 18 is a longitudinal view, in quarter section, of a preferred embodiment of a gas operated plunger;
FIG. 19 is an outer perspective view of the installation of one of the segments underneath a retaining ring;
FIG. 20 is a longitudinal view, in quarter section, of a gas operated plunger which has a chamber and an internal passage and valve closure means in the open position;
FIG. 21 is the top view of the fishing piece of the plunger of FIG. 20;
FIG. 22 is the bottom view of the plunger of FIG. 24;
FIG. 23 is a sectional view of the chamber of the plunger of FIG. 20 with the closure means in the closed position;
FIG. 24 is a sectional view of the chamber of an alternate embodiment of a plunger and a plunger stopper in the open position; and
FIG. 25 is a sectional view of the chamber of an alternate embodiment of a plunger and a plunger stopper in the open position.
 Referring first to FIG. 1, there is shown a producing well W for producing hydrocarbon fluids from a subterranean reservoir R. The well maybe of the horizontal or vertical variety. The plunger pump P is preferably used in wells where the gas pressure alone is insufficient to produce the flow of liquids or the significant flow of fluids at the surface. In these situations, hydrocarbons from such wells cannot be recovered except through the installation of considerably expensive submersible pump units which require daily inspection and maintenance. Similarly, in wells producing primarily gas, the gas production may be substantially impaired by fluids, whether hydrocarbons or salt water, which accumulate in the bottom of the well. In either event, it is desirable to remove fluids from the bottom of such wells without installing conventional pumping units. Typically, one or more well conduits extend from the subterranean reservoir R to the well surface WS. In the preferred embodiment, there is a casing string CS, at the upper end of which is a well head WH, and a tubular string T, also known as “tubulars.” Tubulars T is a generic term used to define the variety of tubes and tubular members, such as cement casings, conduits, and tubing and tubing string, which can also be referred to as the production string, which can be made from a variety of materials such as plastic, metal, and concrete. Tubulars line the well surface and can also be placed inside or on the outside of other tubulars. In any event, the tubulars are the well channels through which fluids from the subterranean reservoir R are raised to the surface. Near the bottom of the tubulars is a tubing stop means TS mounted in any suitable manner. The tubing stop means or mechanism TS may be relocated by wire line or other operations at different depths as well conditions change. The tubing stop TS preferably incorporates a bumper spring B of some type for stopping downward movement of a plunger type pump unit P, which is slidably and sealably disposed in the tubulars T and which will be described in greater detail hereafter. At the well surface WS is a master cutoff or motor operated valve V suitably attached to the tubing string T to entirely block the flow of fluids from the tubulars T as desired. This arrangement further allows retrieval of the plunger pump P for inspection or repair. Above the valve V is a flow tee F and a lubricator L closed at its upper end by detachable end cap E. A bumper sub BS is usually placed therein with a spring (not shown) which is engageable by the plunger pump P when rising through the tubulars TS to stop movement of the plunger P and to cushion the shock created thereby. Connected to the flow tee F is a production or pay line PL in which is installed a motor control valve MV. An electronic controller EC is provided for operating the control motor valve MV. The electronic controller EC is also connected to a tubing plunger sensor S for sensing the pressure within the wellhead WH. A plunger catching device PC may also be attached to the tubing string T above valve V.
 Initially, the plunger P is placed in the tubulars through the lubricator sub L. This is done by removing the cap E while the valve V is closed. Then the cap E is replaced, the valve V opened, and the plunger P is allowed to gravitate or fall to the bottom of the well through the tubulars T. Although the sealing means, such as a jacket 100 made of segments, e.g., 46, 47, 48, 49, is biased outwardly for sliding and sealing engagement with the interior of the tubulars T, there is a small amount of leakage around the outside of the jacket assembly 100 and through the edges of the sealing segments 46, 47, 48, 49. This permits the plunger P to fall under its own weight toward the tubing stop TS which will arrest its downward movement. When this occurs, the cutoff valve V is closed and a time sequence is initiated by the controller EC. Additional fluids enter the tubulars T and the gas and/or fluid pressure begins to build. The controller EC is programmed to keep the valve V closed until substantial fluids have entered the tubulars T and sufficient gas pressure has built up within the well. The amount of time necessary will be different for every well and may change over the life of the well. After a predetermined amount of time, the controller EC opens the valve V, which substantially reduces the pressure above the plunger P. Consequently, the accumulated gas pressure therebelow forces the plunger P, and the fluids trapped thereabove, upwardly through the conduit or tubulars T, through the flow tee F, the valve V and the pay line PL for production of the well. As the plunger P is propelled upwardly through the tubulars T by pressure, it passes through the valve V, and is sensed by the sensor S and eventually movement thereof is arrested by a spring (not shown) in the lubricator sub L. When the plunger P is detected by the sensor S, a signal is transmitted to the controller EC which initiates closure of the valve V. Thereafter the plunger P is allowed to again gravitate or fall to the bottom of the well so that this cycle can be repeated.
 In describing the specific embodiments herein which were chosen to illustrate the invention, certain terminology is used which will be recognized as employed for convenience and having no limiting significance. For example, the terms “upper,” “lower,” “top,” “middle,” “bottom,” and “side” refer to the illustrated embodiment in its normal position of use. The terms “outward” and “inward” will refer to radial directions with reference to the central axis of the device. Furthermore, all of the terminology defined herein includes derivatives of the word specifically mentioned and words of similar import.
 Referring now also to FIGS. 2-25, the drawings show a plunger pump which is used in a gas/fluid lift system in the tubulars T of wells which produce both fluids and gases under variable pressure. Referring now to the drawings in detail, FIGS. 1, 2, 18, and 20 show a plunger which has a body that is slidingly engageable within the well tubulars T. The body is typically made of rigid material, such as any type of metal or metal alloys, rigid plastics and polymers, ceramics, and the like, with the preferred embodiment being made of stainless steel. The body also has an inner core 10, for support and for inner sealing. The core 10 may also be known as a mandrel, and may be solid or hollow. The core is typically substantially cylindrical and typically has the smallest diameter of the plunger body.
 As in FIG. 2, there is a flexible jacket assembly 100 surrounding or mounted about the core 10. The preferred embodiment has four segments 20, 21, 22, and 23, which collectively form a flexible jacket assembly 100. These segments 20, 21, 22, and 23, are made of a relatively rigid material, such as those known in the art, like metal, hard rubber, plastic, graphite, etc., and typically have a relatively smooth outer surface, due to the die cast molding of the segments, and/or polishing of the segments, for sliding and sealing contact with the walls of the well tubulars in which the plunger P is to be used, such as the inner walls of the tubulars T in FIG. 1. Referring now to FIGS. 2, 3 and 4, each segment typically has a substantially convex outer shape 30 and a substantially concave inner surface 32, like that of a semicircular arch. Each segment 20-24, or 46-49 (see FIGS. 5-8) has substantially the same width and curve so that several segments can be placed side by side to form a flexible jacket assembly 100, which is mounted around the core 10, such as by upper and lower retaining rings 150 and 160, respectively. The retaining rings 150, 160, which limit the outward radial movement of the jacket assembly. The inner surface of the jacket assembly 100 is separated from the core 10, unless it is pushed to its most inward position.
 The sealing segments 20, 21, 22, 23, which collectively makeup the jacket assembly 100, are typically held in position around the core 10 of the plunger body by retaining means such as an upper retaining ring 150 and a lower retaining ring 160, which slip on over the core 10, with the upper retaining ring usually abutting the collar 421 of a fishing part 420. As in FIG. 19, the top end 400 of the core 10 is also typically substantially cylindrical and has means such as threading, i.e., a helical or spiral ridge which can be used to removably or securably attach, by screwing, into or onto another part. Alternatively, drilled or threaded holes in both the plunger body and the other part can also be used to securably attach the other parts to the plunger, or they may be connected by threads, welding, soldering, pins, screws or a combination thereof. Other parts includes plunger parts, plunger accessories, or other oil field components or tools.
 The preferred embodiment has a threaded upper end fishing piece 420 which is typically threadingly connected to a threading 430 near the top end of the core 400 and has a head 425 located above a fishing neck 424 of a reduced diameter that is removably attached to the top end 400 and may also be secured with a set screw, e.g., 415. The fishing piece 420 may also have a wrench flat 423, to assist in loosening or tightening. Alternatively, the fishing piece or part 420 may be tooled into the core 10. The lower retaining ring usually abuts an end cap 140. The bottom end 425 of the core 10 typically has means such as threading 435 to attach other parts. In the embodiment of FIG. 18, a plug or end piece 140 is threadedly connected to corresponding threads 435 on the lower end of the core 10, and may have a tapered end 142. The cap may be provided with wrench flats 142 for aiding in the engagement or disengagement of the threaded connection and a set screw (not shown) may be tightened when the cap is fully engaged as to prevent accidental loosening or disengagement. Alternatively, the end cap 140 may be tooled into the bottom end 425 of the core 10.
 The upper and lower ends of each of the segments may also have notches across the ends as in 21 c, 23 c, or recessed ends such as in 21 d, 23 d, which cooperate to fit under the retaining rings 150, 160. This limits the movement of the jacket assembly 100 radially inwardly and outwardly from the core 10. The upper and lower ends of the segments may also be inwardly tapered as in 20 a, 21 a, 22 a, 23 a, so that when the segments engage a restriction in the well tubulars T, the segments will be forced toward their most inward position. This allows the plunger to overcome the restriction and to pass through the restricted area. In their innermost position 290, the segments, e.g., 21-24 and 46-49, have a diameter less than that of any restriction to be encountered in the tubulars. Referring now to FIGS. 1 and 2, the jacket assembly also has the largest diameter 300 of the plunger when the jacket assembly 100 is in its most radially expanded position 300, when it sealingly engages the tubulars. Referring now to FIGS. 1, 3, and 4, the jacket assembly 100 is also slidingly and sealingly engageable within the well tubulars T, based upon the pressure effected by the flow path 200 between the underside of the jacket 100 and the core 10 by the gas and fluids that move upwardly between the segments 20, 21, 22, and 23, and based upon the outward biasing force of the jacket assembly against the tubulars T.
 Typically, the segments are substantially rectangular 25. However, the segments 20, 21, 22, 23, and 46, 47, 48, 49, may be a variety of geometric shapes, sizes, and dimensions, as long as they are able to cooperate to surround the core or to form a jacket assembly 100. One such variation of segments 46, 47, 48, 49 of the preferred embodiment are shown in FIGS. 5, 7-15, 18, and 20. One of the segments 48 is in inner and outer perspective views in FIGS. 5, 7, 8, 9, and 10, and cross-section in FIGS. 11, 12, 13, and 15. FIG. 6 is an upper end view of the segments 46-49. FIG. 14 is a sectional view of the segments 46-49 at section B-B, in their most inward position. Each of these segments 46, 47, 48, 49, is provided with a convex, or substantially convex outer surface, 51, 52, 53, 54, respectively. The inner surfaces of the segments are substantially cylindrical in shape, e.g., 61, 62, 63, and 64. The segments of the preferred embodiment further have sides which have a tab 60 or slotted 61, 67 portion, preferably with a tab 60 on one side and a slot 61, 67 on the opposing side, as in FIGS. 5, 7, and 8. For example in FIG. 5, segment 48 has a tab 60 which is engaged with slot 61 of segment 49. See also segments 46 and 47 in FIG. 14, with tabs 64, 66, respectively and slots 63, 65, respectively. The cross-section of segments 60, 62, 64, 66, as in FIG. 14, show that when the mutually engageable tabs 46, 47, 48, 49 are interconnected with the slots 61, 63, 65, 67 located on the sides of the adjacent segments, that a circumferential jacket assembly 100 is formed. In FIGS. 6, 8, and 9, these tabs, e.g., 60, and slots, e.g., 67, have stepped areas so that a portion of a tab 60 a overlaps an inset portion of a corresponding slot 67 a, 67 b. The overlapping is accomplished with opposing surfaces, e.g., 67 a and 60 a, which are slidably engageable with the opposing surfaces of the adjacent segments 46-49, and which guide the segments inwardly and outwardly between their innermost and outermost radial positions. These overlapping, opposing, sealing surfaces are planar surfaces which are tangentially disposed relative to a cylinder whose axis corresponds with the axis of the core 100 of the plunger body about which the segments are disposed. The overlapping surfaces further minimize leakage from the flow path 200 of FIGS. 16, 17, between the core and the segments, and therefore assist in inner sealing.
 The upper and lower ends of these segments may also be inwardly tapered as at 51 a, 52 a, 53 a, 54 a, and 51 b, 52 b, 53 b, 54 b, respectively, so that when the segments engage a restriction in the well tubulars, the segments will be forced inwardly to allow the plunger to pass through the restriction. In the preferred embodiment, the upper ends of each segment have a semicircular notch 70, 72, 74, 76, as do the lower ends of such segments 71, 73, 75, 77, which slidably fit under the lugs, e.g., 153, 163, 164 of the retaining rings. See FIGS. 18, 19.
 The preferred embodiment further has segments wherein the inner surface or underside, e.g., FIGS. 7, 16, possess at least one finger 120 which is preferably made of rigid material, such as metal, plastic, hard rubber, graphite, and the like. The rigid fingers 120 of the exemplary embodiment are made of metal and are an integral part of the segment 46, 47, 48, 49 which is molded. The exemplary embodiment has three fingers 120 on the underside of each segment 61, 62, 63, 64, respectively. See, for example, FIG. 6. Preferably, there is a plurality of rigid fingers on each segment underside, with the preferred embodiment, e.g., FIGS. 4, 7, 19, having three such fingers 120 on the underside of each segment 32, 63, respectively. The fingers 120 of each segment protrude radially inward toward the core 10 and are parallel and horizontally aligned with the fingers 120 of the adjacent segments to collectively cooperate to encircle the core 10, and serve as part of the internal sealing means. The fingers 120 and one 10 are typically separated by space, or a flow path 200 unless the fingers are pushed to their most inward position. If the core 10 also has grooves, e.g., 12, 14, 16, the fingers 120 on the underside of the segments 46, 47, 48, 49 are adjacent to and aligned with the grooves 12, 14, 16, and the fingers 120 fit into the grooves, 12, 14, 16. See FIGS. 3, 19. Where both fingers and grooves are present, there is an increased surface area between the inner surface of the segments and the core which energizes the segments and pushes the segments outwardly to cause an external seal with the tubulars. Typically during operation, the fingers 120 and core 10 or core grooves 12, 14, 16, are separated by a space, or flow path 200.
 As in FIGS. 3, 7, 13, each finger 120 is defined by top 120 f and bottom side surfaces 120 b. The fingers 120 may be in a variety of geometric shapes. For example, the fingers 120 may have a cross-section such as that of a V-shape, wherein the top and bottom sides converge (not shown), or conversely the side surfaces may diverge with respect to one another (not shown). In the preferred embodiment, the fingers 120 also have an inner surface 120 d which is a curved concave shape, which is complimentary to the shape of the core 10. However, the inner surface of the finger 120 could also be semicircular in cross-section, with a convex inner surface (not shown). Many other variations and combinations thereof are also possible. Further, the finger has first 125 a and second side edges 125 b which are flat and angularly aligned with the first and second adjacent side edges of the segment, e.g., 48 a, 48 b, respectively. The elevation of the fingers 120 may vary. In the embodiment having a grooved core 12, 14, 16, the elevation of the fingers 120 may be at least as great as the depth, e.g., 18 b of the groove, e.g., 12, 14, 16, 18, or conversely, less than the depth of the groove 12, 14, 16. However, the fingers 120 must be of a narrower width than that of the corresponding groove, so the fingers 120 can fit into such grooves, e.g., 12, 14, 16. See FIGS. 18, 19. Further, the fingers 120 may be of a uniform or variable elevation, shape, and width with respect to one another.
 Now referring back to the fingers on the underside of the segments, in the preferred embodiment, the top and bottom side surfaces 120 f, 120 b of the finger 120 has an angle of substantially 90 degrees, relative to the outer surface of the core 11, and has an inner surface 120 d which is substantially parallel to the outer surface of the core 10. The finger 120 of this design has a square or rectangular cross-section. See, e.g., FIGS. 5, 18, 20.
 Alternatively, the fingers may be located on the surface of the core 11, and would be referred to as “bands” (not shown). The core may have one circumferential band, or a plurality of circumferential bands. In this case, the bands have corresponding elements and features equivalent to those found in the fingers. The bands may be found in an embodiment with or without corresponding furrows on the underside of the segments (not shown). In this case, the furrows have corresponding elements and features equivalent to those found in the grooves of the core. The underside of the segments may have one furrow, or a plurality of furrows which collectively form a circumferential furrow. When there are both bands and furrows present (not shown), the bands on the surface of the core 11 (not shown) fit into the corresponding furrows on the underside of the segments (not shown). The bands maybe a variety of shapes and widths, similar to those described for the fingers. Preferably, the band has a flat bottom side and a flat top side and a curved outer surface. The bands may also have a variety of elevations, and may be at least as great or less than the depth of the furrow (not shown). Similar to the plurality of fingers and grooves, a plurality of bands and/or furrows create a tortuous path of flow for fluids and gases and an increased surface area between the undersides of the segments and the core which would energize the segments and push the segments outwardly to cause an outer seal with the tubulars. Further, a plurality of bands and/or furrows also provides a tortuous path of flow and effects an inner turbulent seal and retards the upward flow of fluids and gases and causing an increase in pressure below the plunger. Similar to the fingers and grooves, the biasing means may be placed between the core and the segments. Also similarly, there may be at least one blind hole in each band which accommodates a biasing means, discussed below, under each segment. The biasing means may also be disposed between the band and the furrow (not shown). Further, at least one furrow in each segment may have a blind hole which accommodates the biasing means with the biasing means being disposed between the band and the furrow (not shown).
 The core 10 of the plunger body in FIGS. 16, 17, 18 may also possess internal sealing means such as one grove or a plurality of longitudinally spaced circumferential grooves 12, 14, 16, 18 which are defined by recessed surfaces that are interspersed between the ungrooved sections of the surface of the core 11. There is also an inner turbulent sealing effect, FIG. 4, when the embodiment has an ungrooved core and at least one, or preferably a plurality of fingers, e.g., 120 which project inwardly toward the core 11. There is an even more dramatic inner sealing effect where the embodiment has grooves 12, 14, 16 as well as projections, e.g., 120.
 Each groove, e.g., 12, 16 is defined by a recessed surface, e.g., 12 b, 18 b and upper and lower side surfaces, e.g., 18 a and 18 c, respectively. In the preferred embodiment, the lower surface portion 12 b, 18 b has an angle of substantially 90 degrees, relative to the outer surface of the core 11, and have upper and lower portions 12 a, 12 c, and 18 a, 18 c, that have an angle of substantially 90 degrees, relative to the outer surface of the ungrooved core 11 a. The core of this design has a square or rectangular cross-section, see, e.g., FIG. 16. The preferred embodiment of the plunger has a core 10 which includes a plurality, preferably three, of longitudinally spaced circumferential grooves, e.g., 12, 14, 16, that divide the peripheral surface of the core 11 into a plurality of outer surface sections, e.g., 11 a, 11 a. Again, due to the necessity for clearance between the plunger P and the tubulars T which allows the plunger to fall or gravitate to the bottom of the well, a flow passage is formed between the jacket and the tubulars, and some of the gas below the plunger P will flow up between the plunger P and the tubulars T, as well as up into the plunger beneath the jacket assembly and the core. As shown in FIGS. 16, 17 the gas also enters into the flow path 200 between the segment 48 and the core surface 11, 11 a, a first portion F.sub.1 of the gas flows along the surface of the ungrooved core 11 a and the segment underside 63, and a second portion F.sub.2 flows down into the groove, e.g., 16, 18 and recessed surface, e.g., 18 b. The four right angles at each corner, 13 a, 13 b, 13 c, 13 d, and along the recessed surface 18 b and the top 18 a and bottom sides 18 c of the groove 18 cause the first portion F.sub.1 and second portion F.sub.2 of flowing gas meet at substantially a right angle at the corner 13 a, creating a turbulent flow region T.sub.1, that inhibits liquid flow downward into the groove and inhibits gas flow upward out of the groove. The gas flowing up along the plunger core surface 11, 11 a dissipates energy at each successive groove, e.g., 16, 14, 12. Alternatively, the grooves may be located in the underside surfaces of the segments, e.g., 46-49 (not shown). In that situation, the grooves would have corresponding elements and features equivalent to those found in the grooves, e.g., 12, 14, 16.
 The groove may also be in the form of a spiral, or conversely in a variety of geometric shapes, and, for example, may have a cross-section such as that of a V-shape, or top and bottom sides that converge or diverge with respect to one another, or a semicircular cross-section (not shown). Many other variations are also possible. For example, the depth and/or length of the recesses, e.g., 18 b, may be variable, as well as the length of the body sections 11 a between the recesses. Further, the grooves, e.g., 12, 14, may be of a uniform or variable depth, shape, and width, with respect to one another.
 As best seen in FIGS. 16, 18, the preferred embodiment may also have biasing means, which are typically springs 190, disposed between the core 10 and the underside or inner surface of the segment, e.g., 61, 62, 63, 64 which biases the segments, e.g., 46, 47, 48, 49, outwardly from the core 10. The biasing means may take the form of a helically wound spring 190 or leaf spring or other member which has the ability to rebound or recoil after being compressed. Further, the core 10 may possess a blind hole 180, or a blind hole 182 may be present in the core groove 185, e.g., 12, 14, 16. Preferably there are two biasing means, e.g., 190 between each segment, e.g., 46, 47, 48, 49 and the adjacent area of the core 10 or core groove, e.g., 12, 14, 16. The biasing means 190 are preferably placed about midway across the width of the segment and at places along the length of the underside that leave the segment balanced against the core 10. The blind holes, e.g., 180, 182, accommodate and hold the biasing means, e.g., 190 in place. The finger of the preferred embodiment may also have a blind hole 185 which accommodates a biasing means, e.g., 190. Preferably the embodiment has a blind hole in both the core 180 or core groove 182 and the underside of the adjacent segment 185 (not shown) or finger 120. This design minimizes the risk of loss of the biasing means 190.
 Referring to FIG. 1, the gas below the plunger P must have sufficient pressure to overcome the weight of the plunger P and a liquid slug LS on top of the plunger P, and the pay line PL pressure, in order to move the plunger P up the tubulars T. Due to the necessity for clearance between the plunger P and the tubulars T which allows the plunger to fall or gravitate to the bottom of the well, a flow passage is formed between the jacket 100 and the tubulars T, and some of the gas below the plunger P will flow up between the plunger P and the tubulars T, as well as up into the plunger beneath the jacket assembly 100 and the core 10. As shown in FIGS. 16, 17 once the gas and/or fluids enter into the flow path 200 between the segment 48 and the core surface 11, 11 a, a first portion F.sub.1 of the gas flows along the surface of the core 11 and the segment underside 63, and a second portion F.sub.2 flows down and around the raised finger 120. The four right angles at each corner of the finger, 120 a, 120 c, 120 e, 120 g, and along the surfaces of the bottom 120 b and top sides 120 f and inner surface of the groove 120 d, cause the first portion F.sub.1 and second portion F.sub.2 of flowing gas to meet at substantially a right angle at the corner 120 e, creating a turbulent flow that inhibits liquid flow downward into the areas of the segment between the fingers which have lower elevations and inhibits gas flow upward out of the segment area between the fingers. The gas flowing up along the plunger core surface 11, 11 a dissipates energy at each successive finger, e.g., 120. There is an even more dramatic inner sealing effect where the embodiment has some grooves 12, 14, 16 in the core 10, as well as projections, e.g., 120, FIGS. 16, 18.
 The sealing segments 46-49 are mounted around the core 100 of the plunger body and are preferably held in place by a retaining means such as an upper retaining ring 150 and a lower retaining ring 160. See FIGS. 2, 4, 18, 19. The retaining rings 150, 160 are substantially cylindrical and have a hollow inner surface of slightly larger diameter than the core 10 and a shape which corresponds to the shape of the core 10. The retaining rings also have first 151, 161 and second 152, 162 ends, with the first ends 151, 161 having a plurality of lugs positioned next to the segments, and the seconds ends being positioned on the opposite side of the segment ends. Preferably the retaining rings 150, 160 have a plurality of lugs, e.g., 163, 164, preferably four, which are spaced at ninety degree intervals around the retaining rings 150, 160, and which are positioned to protrude inwardly toward the segments and are oriented to engage the notches 70, 72, 74, 76 at the upper ends of the segments 46, 47, 48, 49, as in FIGS. 5, 6, and the lower ends of the segments, e.g., 71, 73. The retaining rings 150, 160 may also serve to hold the fingers 120 in position over the grooves, e.g., 12, 14, 16, 18, in the core 10. The upper retaining ring 150 is slipped over the core 100 of the plunger body and is positioned adjacent to the segments, 46-49, and may also be adjacent to the shoulder 410 of the fishing piece 420, which may be tooled into the top end of the core 10, or removably attached to the body such as by threading 430. The retaining 150, 160 rings may be held in place by a set screw 415, which is screwed into a drilled hole 420 in the core 10. See FIGS. 18, 19. Similarly, the lower retaining ring 160 is slipped over the core 100 of the plunger body and is positioned adjacent to the segments, 46-49, and may also be adjacent to the end cap 220, which may be tooled into the bottom end of the core 10, or removably attached to the body such as by threading 225, and may also have corresponding lugs. Alternatively, the segments, e.g., 21, 23, 48 may have a slotted, e.g., 21 c, 23 c or notched top, e.g., 70 and bottom ends, e.g., 71 which slidably fit under the retaining rings, and limit the outward radial movement of the segments, e.g., 21, 23, 48.
 Further, in an embodiment having a grooved core, e.g., 12, 14, 16 and fingers 120, and upper 150 and lower retaining rings 160, the bottom edge of the uppermost groove, e.g., 16 of the core 10 is angularly reduced to allow installation of the segments 46, 47, 48, 49 underneath the upper retaining ring 150. Or in the alternative, the top edge 12 a of the lowermost groove, e.g., 12 of the core is angularly reduced 12 k to allow installation of the segments with fingers 120 underneath the lower retaining ring 160. See FIG. 19. Of course the fingers 120 of the segments, e.g., 46-49, may also be present in plungers with grooved cores 12, 14, 16, with fingers interspersed in the core grooves. In that case, at least one outer top edge of one of the grooves, e.g., 12, or grooves, e.g., 12, 14, 16, is angularly reduced to allow installation of the segments with fingers 120 underneath the retaining rings, e.g., 150, 160.
 Referring now to FIGS. 1, 20-25, the operation of an additional embodiment of a plunger a will be explained. FIGS. 20-25, illustrate an alternate embodiment of the invention which in many respects is the same as the embodiments of FIGS. 1-19. Similar to the previous embodiments, the plunger of FIGS. 20, 23, 24, and 25 has a body with a core 10, but also has areas defined as a top end 400, and a bottom end 500. The top end 400 has threading 430 to which additional parts can be attached. In this embodiment, a separate piece, such as a fishing part 420 is threadingly connected to the body at a threaded connection 430. The top end fishing piece 420, like some of the previous embodiments, is provided with a head area 425 and a reduced neck 424 for engagement by a fishing tool if required. The bottom end 500 is provided with an external thread 435 to which additional parts can be attached such as a modified end cap 220 with a corresponding internal thread 221, provides a threaded connection between the body and the end cap 220. The modified end cap 220 includes an enlarged chamber portion 510. The plunger is also provided with an inner flow passage 460 which may extend partway through or through the entire body and plunger, a chamber 510, and a closure means 600. The major difference between the plunger of FIGS. 2 and 18 and the previously described features of FIGS. 2-19 is the inner flow passage 460 and the chamber 510 and closure means 600. Like in the previously described embodiments, the plungers of FIGS. 20-25 is provided with an outer seal means made up of a plurality of segments, e.g., 46, 47, 48, 49, or 20-24, which are substantially similar, if not identical, to the corresponding elements in the embodiments of FIGS. 2-19. Retaining rings 150 and 160 hold these segments 46, 47, 48, 49, or 20-24, collectively the jacket assembly 100 in place but permit yet limit outward radial movement between an innermost position 290, in which the exterior cylindrical surfaces thereof lie has a diameter less than that of any restriction to be encountered in the tubulars T with which it is to be used, and an outermost position 300 in which the exterior cylindrical surfaces, e.g., 46, 47, 48, 49 slidingly and sealingly engage the walls of the tubulars T in which the plunger P is to be used. Biasing means such as springs 190, bias these segments toward their outermost position 300. The unique circumferentially and mutually engageable tabs and slots and the overlapping opposing tangentially disposed planar surfaces provided by stepped areas, as in FIGS. 5, 6, 8, 14 thereon allow radial inward and outward movement while limiting leakage and erosion caused thereby.
 As in the embodiments shown in FIGS. 2-19, the body of the plunger also includes an internal sealing means, such as the inner surfaces of the segments 61, 62, 63, 64, respectively, which may also have rigid fingers 120 projecting inwardly. Or alternatively, the raised surfaces may be in the form of a rigid band on the surface of the core 11 (not shown). Preferably, each segment, e.g., 46-49 has three fingers 120 on the underside of each segment 61, 62, 63, 64, which protrudes radially inward toward the core 10. The fingers 120 of each segments, e.g., 46-49 are parallel and horizontally aligned with the fingers of the adjacent segments so the fingers collectively cooperate to encircle the core 10. As in the previous embodiments, the preferred internal sealing means also includes a core 10, wherein the surface 11 is grooved, e.g., 12, 14, 16. Where there are both grooves 12, 14, 16, in the surface of the core 11 and fingers 120 on the segments 46, 47, 48, 49, the fingers 120 are adjacent to and fit into the grooves 12, 14, 16, in the core. The fingers 120 are typically separated from the core 10 unless the fingers are pushed to their most inward position. Typically during operation, the fingers 120 and core 10 are separated by a space, or flow path 200. This arrangement of grooves and/or finger projections (or a band located on the core 10, not shown) creates a tortuous path of flow that effects an inner turbulent seal.
 The chamber 510 which houses the closure means, such as a stopper 600, is an enlarged area within the end cap 200. As previously mentioned, the end cap 200 is threadingly connected to the lower plunger body portion 500 at the threaded connection 435. It may be inwardly tapered 221 below the chamber 510. The chamber 510 has a roof 520 at the upper end which may be inwardly tapered 221 below the roof 520, with an opening 525 in the roof which communicates with the upper inner flow passage 460 and a floor 550 at the lower end with an opening into a bore which is typically narrower than the flow passage 460 and which houses the stem 630 when the closure means is in the open position. Furthermore, there is an opening 560 at the end of the stem bore flow passage 560 at the bottom of the end cap 570, and the stem protrudes downward 670 from the body of the plunger in the open position. In the preferred embodiment, the roof 520 of the chamber 510 is substantially curved 522 and has a stopper 600 with a head 615 whose top end 610 is correspondingly curved 605, like the roof 520. Alternatively, the roof 520 may be triangular in cross-section and the head of the stopper is correspondingly cone-shaped. See FIGS. 24-25. There are also other variations of additional shapes which the chamber roof and chamber floor could possess, such as a flat roof and a curved floor (not shown), and corresponding variations of the shape of the first end and second end of the stopper, such as a flat top end and a circular bottom end (not shown), which could also be operable.
 The roof 520 of the chamber 510 is further connected to a downwardly facing and tapered seating surface 530. The area below the seating surface 530 is also provided with an area partially defined by a slanted or tapered ramp area 545 below the seating surface 530. The seating surface 530 of the preferred embodiment is sized and designed to receive and guide a plunger stopper closure member 600 albeit rounded, half-sphere, or ball-type, upwardly to the seating surface 605 in the roof 520. The plunger stopper 600 has a head 615 with a top end 610 and a bottom end 630, wherein the bottom end of the stopper is substantially curved 635. Conversely, the bottom end of the stopper may be substantially flat 630. A stem 650 which is rounded and has flat sides 652 and a substantially rounded bottom 655 is attached to the bottom end 630 of the head 615. Alternatively, the top end 610 of the plunger stopper 600 may further have a stem 630 which is attached to the top end 610 of the head 615. This stem 680 will be pushed up into the inner flow passage 460 above the chamber 510, when the bottom end 570 of the plunger hits the bottom well stop means to further ensure closure of the opening 525 into the flow passage 460. (See FIGS. 24, 25). Under certain conditions, the stopper 600 is moveable between the open position of FIG. 20, in which fluid and/or gas flow is permitted into the inlet ports, e.g., 700, 702 in the end cap 220 through the chamber 510 and into the flow passage of the body 460, through the hole 525 in the roof 520, and out through the outlet ports, e.g., 715, 716, 717, 718 in the top end 400. In FIG. 21, the stopper 600 is in a closed position in which the fluid and/or gas flow through the chamber opening 545 into the flow passage 460 of the plunger body is blocked by the top 610 of the stopper 600. In the open position, the stem 650 extends downwardly through the opening 555 in the hole in the floor 500 of the chamber 510 into the bore 540 in the bottom of the end cap 560, and protrudes 670 from the lower end of the plunger body 570, when the plunger is descending through the tubulars T, or at the surface once the pressure valve V has been opened. When the stem 655 and then the bottom end of the plunger reach the bottom of the well, or some type of bottom well stop or well stop means SM, the stem 650 and stopper head 615 is forced or pushed upwardly until the top end of the head 610 is seated against the seating surface 530 of the roof 520 of the chamber 510.
 The fishing part which is attached to the top end also has an inner flow passage 460. In one embodiment, the inner flow passage 460 also has an opening 720 at the top end of the plunger. As previously discussed, the fishing part 420 may also have a plurality of outlet ports 715, 716, 717, 718, or axial inner passages, disposed around the sides of the collar 410 of the fishing piece 420, in addition to, or instead of the opening at the top end 720. Preferably, there are four radial ports, e.g., 715, 716, 717, 718 which are spaced along the cylindrical axis of the collar at about 45 degrees from each other.
 Similarly, there are preferably four radial ports which are spaced along the cylindrical axis of the end cap 220 at about 45 degrees from each other 700, 701, 702, and 703. The location of the inlet ports, e.g., 700, 702 in the chamber wall 511 of the end cap 220 are especially important. The ports 700, 702 are preferably located so that the inside openings of the ports 710, 712 into the chamber 510 are located above the top end 610 of the plunger stopper head 615 when the stopper 600 is in its downward position. Furthermore, these inlet ports are preferably located so that the inside opening of the ports 710, 712 will be below the bottom end 630 of the stopper head 615 when the stopper is in its upward position, closing the inner flow passage 460. This placement of the inlet ports assures the bypassing of fluids through the chamber passage 510 and into inner flow passage 460 as the plunger falls in the tubulars T.
 The plunger of the embodiment of FIGS. 20-24 also operates much as the plunger embodiment of FIGS. 2-5 and 6-19, and may be described with reference to FIG. 1. Like the plunger P of FIGS. 1, and 2-19, the plunger of FIGS. 20-25 may be placed in the tubing string T and allowed to fall or gravitate to the bottom of the well W for producing the subterranean formation F thereof. However, it will fall more rapidly due to the inner passage 460. When the bottom end of the plunger 570 reaches the well stop or stop means, the stem 650 of the closure means such as the stopper 600, and the head member 615 are pushed upwardly toward the roof and to the seating surface 530 and the closure means or stopper 600 is seated against the roof 520. When the plunger P reaches the tubing stop SM at the bottom of the tubulars, the weight of the plunger pushes against the well stop SM forcing the stopper stem 650 and head 615 in an upward direction. As soon as the closure member 212 enters the flow path of valve passage 202, 203, 205, the top end 710 of the stopper 600 then proceeds past the ramp area 545 and up into the seating surface 530 in the roof 520. Once the stopper 600 is seated to assume its closed position seated, the flow of fluids into the chamber through the inlet ports, e.g., 702, 710 will flow up into the chamber 510 and against the second end of the plunger head 530 will cause the stopper to assume and maintain its closed position against the seating surface 530 as illustrated in FIGS. 23, 25. At this point, the bypassing of fluid through the flow passage 460 is blocked and gas pressure is allowed to build up just as with plunger 1 and 2 of the embodiment illustrated in FIGS. 2-4 and 5-19. After a preselected, predetermined period of time, the control valve V at the surface is opened by the controller EC and the gas pressure built up in the well causes the plunger and any well fluids accumulated in the tubulars T thereabove to be elevated to the surface and produced through the production or pay line PL. Once the plunger is detected by sensor S and the control valve V closed by the controller EC, pressure is equalized in the area of the lubricating sub E. When that occurs the plunger stopper 600, due to its own weight, falls back down and reassumes its open position of FIGS. 20-24. This opens the inner flow passage 460, allowing the plunger to descend to the bottom of the well W to repeat the cycle.
 The plunger of the present invention has a number of unique elements. However, many variations of the invention can be made by those skilled in the art without departing from the spirit of the invention. Accordingly, it is intended that the scope of the invention be limited only by the claims which follow. Of course, the present invention is not intended to be restricted to any particular form or arrangement, or any specific embodiment disclosed herein, or any specific use, since the present invention may be modified in various ways without departing from the spirit or scope of the claimed invention herein. Furthermore, the figures of the various embodiments is intended only for illustration and for disclosure of operative embodiments and not to show all of the various forms or modifications in which the present invention might be embodied or operated. The present invention has also been described in considerable detail in order to comply with the patent laws by providing full public disclosure of at least one of its forms. However, this detailed description is not intended to limit the broad features or principles of the present invention in any way, or to limit the scope of the patent monopoly to be granted.