US20160090827A1

US20160090827A1 - Two-Piece Plunger with Sleeve and Spear for Plunger Lift System

Info

Publication number: US20160090827A1
Application number: US14/502,054
Authority: US
Inventors: Manish Agarwal; Michael S. Juenke
Original assignee: Weatherford Technology Holdings LLC
Current assignee: Weatherford Technology Holdings LLC
Priority date: 2014-09-30
Filing date: 2014-09-30
Publication date: 2016-03-31

Abstract

A plunger lift system has a plunger with a sleeve and a spear that dispose in tubing. The sleeve and spear can move in the tubing between a bumper and a lubricator. The sleeve has a passage for fluid to pass therethrough, and the spear can insert partially into the sleeve's passage. The sleeve and spear fall independently of one another from the surface to the bumper. When disposed on the bumper, the sleeve and spear mate together. Building gas pressure downhole can then lift the mated sleeve and spear, which can sweep liquid along the tubing and push the liquid along with them to the surface.

Description

BACKGROUND

Liquid buildup can occur in aging production wells and can reduce the well's productivity. To handle the buildup, operators can use beam lift pumps or other remedial techniques, such as venting or “blowing down” the well. Unfortunately, these techniques can cause gas losses. Moreover, blowing down the well can produce undesirable methane emissions.
In contrast to these techniques, operators can use a plunger lift system, which can de-liquefy a gas well, reduce gas losses, and improve well productivity. The plunger lift system can use one of two types of plungers: a conventional plunger and a continuous (bypass) plunger. The conventional plunger is typically used to lift built-up fluid at the downhole end of the tubing string.
A continuous plunger is typically used when the well is still flowing at very high flow rates, above critical velocity, during early intervention of the well. To do this, the continuous plunger is designed to fall against the flow of the well and uses a valve on the plunger, such as an internal shifting rod. When the plunger lands downhole on the bumper, the valve is closed. Then, when built-up pressure lifts it in the tubing, the continuous plunger is primarily used to sweep accumulated fluids along the tubing wall.
For example, a plunger lift system 10 of the prior art is shown in FIG. 1A. In the system 10, a plunger 50A is disposed in production tubing 16, which is deployed in casing 14 from a wellhead 12. During operation, the plunger 50A moves between a lubricator 30 at the surface and a landing bumper 20 downhole.
The plunger 50A shown in FIGS. 1A-1B is a two-piece plunger of the continuous type. By contrast, a conventional plunger 50B as shown in FIG. 2 has a single body that may be solid or semi-hollow and that has external ribbing or the like for creating a pressure differential. The continuous plunger 50B as in FIG. 2 is used when liquid build-up has become an issue in part because the well is not flowing above critical velocity. The two-piece plunger 50A of FIGS. 1A-1B, however, can be used in a well that is still flowing above critical velocity and liquid build-up has not become a significant issue yet.
The two-piece plunger 50A of FIGS. 1A-1B allows both pieces to fall faster downhole than would be possible for such a solid or semi-hollow plunger 50B of the prior art. As best shown in FIG. 1B, the two-piece plunger 50A has a separate sleeve 60 and ball 70. The sleeve 60 has an inner bore 62 that defines a seat 68. The ball 70 can fit against the seat 68 and can seal fluid flow up through the plunger's bore 62 during operation. The sleeve's outer surface can have ribbing 64 or the like for creating a pressure differential. Particular examples of this type of two-piece plunger 50A and its use are disclosed in U.S. Pat. No. 6,467,541 and U.S. Pat. No. 6,719,060.
When used in the system 10 of FIG. 1A-1B, the sleeve 60 and ball 70 dispose separately in the tubing 16. The ball 70 drops first to land near the bottom of the well. The ball 70 falls into any liquid near the bottom of the well and contacts the bumper 20. The sleeve 60 drops after the ball 70 so it can fall to the bumper 20 as well. Thus, during operations, the ball 70 falls in the well first followed by the sleeve 60 against high flow rates. They travel independently of each other. When they reach the bottom of the well, they unite and can then travel back to the surface to de-liquefy the well.
When the sleeve 60 reaches the ball 70, for example, they unite into a single component. With the plunger 50A deployed to handle liquid buildup, operators set the well in operation. Gas from the formation enters through casing perforations 18 and travels up the production tubing 16 to the surface, where it is produced through lines 32/34 at the lubricator 30. Liquids may accumulate in the well and can create back pressure that can slow gas production through the lines 32/34. Using sensors and the like, a controller 36 operates a valve 38 at the lubricator 30 to regulate the buildup of pressure in the tubing 16. Sensing the slowing of gas production due to liquid accumulation, the controller 36 shuts-in the well to increase pressure in the well.
As high-pressure gas accumulates, the well reaches a sufficient volume of gas and pressure. Eventually, the gas pressure buildup pushes against the combined sleeve 60 and ball 70 and lifts them together to the lubricator 30 at the surface. The column of liquid accumulated above the plunger 50A likewise moves up the tubing 16 to the surface so that the liquid load can be removed from the well.
In this way, the plunger 50 essentially acts as a piston between liquid and gas in the tubing 16. Gas entering the production string 16 from the formation through the casing perforations 18 acts against the bottom of the plunger 50A (mated sleeve and ball 60/70) and tends to push the plunger 50A uphole. At the same time, any liquid above the plunger 50A will be forced uphole to the surface by the plunger 50A.
As the plunger 50A rises, for example, the controller 36 allows gas and accumulated liquids above the plunger 50A to flow through lines 32/34. Eventually, the plunger 50A reaches a catcher 40 on the lubricator 30 and a spring (not shown) absorbs the upward movement. The catcher 40 captures the plunger's sleeve 60 when it arrives, and the gas that lifted the plunger 50A flows through the lower line 32 to the sales line. A decoupler or striker rod (not shown) inside the lubricator 30 can separate the ball 70 from the sleeve 60. The ball 70 can then immediately fall toward the bottom of the well. In the meantime, the catcher 40 holds the sleeve 60 and then releases the sleeve 60 after the ball 70 is already on its way down the tubing 16.
Dropped in this manner, the sleeve 60 and ball 70 fall independently inside the production tubing 16. The sleeve 60 with its central passage 62 can have gas flow through it as the sleeve 60 falls in the well. On the other hand, flow travels around the outside of the ball 70 as the ball 70 falls in the well. Unfortunately, the ball 70 tends to fall slower than the sleeve 60. In fact, the ball 70 can knock about against the tubing 16 when falling through high gas flow.
Therefore, the system 10 must properly time the dropping of the ball 70 and sleeve 60 so that the ball 70 has sufficient time to fall downhole before the sleeve 60 is allowed to fall. Solutions for decoupling the ball 70 and for timing the dropping of the ball 70 and the sleeve 60 are disclosed in U.S. Pat. No. 6,467,541 and U.S. Pat. No. 6,719,060, for example. Although such schemes may be effective, what is needed is a more robust approach with less complexity.
Other two piece plunger designs are disclosed in U.S. Pat. No. 6,148,923; U.S. Pat. No. 6,209,637; U.S. Pat. No. 7,383,878; and U.S. Pat. No. 8,485,263. For example, the two-piece plunger as disclosed in U.S. Pat. No. 6,209,637 has an upper sleeve and a lower mandrel. The upper sleeve has a tubular body with a central passage. The lower mandrel is a body with a robust lower end, two centralizer sections with outward extending arms, a circular plate with slots, and a pin at the top. The pin is shorter than the sleeve and nests therein with a sealing member. In a similar configuration, the two-piece plunger as disclosed in U.S. Pat. No. 7,383,878 has an upper sleeve and a fluted lower mandrel. A short head at the top of the mandrel latches in the sleeve.
In another example, the two-piece plunger as disclosed in U.S. Pat. No. 8,485,263 is reproduced in FIGS. 3A-3B. This plunger 50C is a multi-sleeve plunger having a main sleeve 80 and an ancillary sleeve 90 that can mate and unmate during operations. The main sleeve 80 has a cylindrical body with an internal passage 82 through which flow can pass as the sleeve 80 falls in the well. Similarly, the ancillary sleeve 90 also has a cylindrical body with an internal passage 92 through which flow can pass as the sleeve 90 falls in the well.
Turning to the main sleeve 80, the exterior of the main sleeve 80 can have ribbing 81 or other features for creating a pressure differential across the sleeve 80 when disposed in tubing. The sleeve's internal passage 82 can define a fish neck or other profile 86 allowing for retrieval of the sleeve 80 if needed. At its distal end, the main sleeve 80 defines a narrow stem 84 on which the ancillary sleeve 90 can fit when mated thereto. The distal end of this narrow stem 84 has a nodule 85 and defines ports 88 communicating with the sleeve's internal passage 82. These ports 88 allow flow through the main sleeve's internal passage 82 as it falls in the well.
Turning to the ancillary sleeve 90, its internal passage 92 can also have a fish neck profile 96 for retrieval. The uphole end of the ancillary sleeve 90 is open to fit onto the main sleeve's narrow stem 84. The lower end of the ancillary sleeve 90, however, is closed except for an orifice 95 through which the nodule 85 of the main sleeve 80 can fit when mated thereto.
The two sleeves 80/90 when uncombined can allow fluid to pass through their passages 82/92 as they fall down the tubing. When landed on the bumper downhole, the two sleeves 80/90 can combine or mate with one another to close off fluid flow therethrough. When combined, the ancillary sleeve 90 covers the slots 88 in the main sleeve's stem 84, and the stem's nodule 85 closes off the ancillary sleeve's orifice 95. The sleeves 80/90 remain mated together while disposed on the bumper and when pressure lifts the sleeves 80/90 and liquid column to the surface.
As the above examples show, there are several ways to implement a plunger lift system. However, operators are continually striving to develop more efficient and effective plunger lift systems to increase the production from a gas well. Systems in the prior art may require longer cycle times for the plunger to fall, for pressure to build-up, and for liquid to then be lifted. The well may need to be shut in for longer periods than desired, and reduced amounts of gas may be produced over time as a result.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.

SUMMARY

In one arrangement, a plunger lift apparatus for tubing in a well has a sleeve and a spear. The sleeve for disposing in the tubing defines a passage therethrough from a first proximal end to a first distal end. The spear for disposing in the tubing downhole of the sleeve is elongated, extending from a second proximal end to a second distal end. The spear's second distal end is longer than its second proximal end. The second distal end of the spear inserts in the passage of the sleeve, and the second proximal end of the spear mates with the first proximal end of the sleeve. The spear at least partially closes fluid communication through the passage of the sleeve when mated therewith.
In another arrangement, a plunger lift apparatus for tubing in a well has a sleeve and a spear. The sleeve for disposing in the tubing defines a passage therethrough. The spear for disposing in the tubing downhole of the sleeve mates with the sleeve downhole and at least partially closes fluid communication through the passage of the sleeve when mated therewith. In some arrangements, the spear deploys at a faster rate downhole in the tubing than the sleeve.
In yet another arrangement, a plunger lift apparatus for tubing in a well has a sleeve and a spear. The sleeve for disposing in the tubing defines a passage therethrough and has a first ratio of cross-sectional area to weight. The spear for disposing in the tubing downhole of the sleeve mates with the sleeve downhole and at least partially closes fluid communication through the passage of the sleeve when mated therewith. The spear has a second ratio of cross-sectional area to weight ratio being less than the first ratio of the sleeve.
In the various arrangements, the sleeve and the spear mated together move uphole within the tubing by application of a pressure differential. To facilitate this, the sleeve can have means for producing a pressure differential across the sleeve by using a contoured surface, ribs, brushes, pads, etc.
A catcher disposed uphole of the tubing can be operable to engage the sleeve when reaching the surface, and a controller operably coupled to the catcher can control engagement of the catcher with the sleeve. Additionally, the controller can operate a valve in fluid communication with the tubing based on a condition in the tubing.
As noted above, the spear can deploy at a faster rate downhole in the tubing than the sleeve, although other arrangements are possible. Overall, the spear has a first weight greater than a second weight of the sleeve, has a first cross-sectional area that is greater than a second cross-sectional area of the sleeve, and has a first axial length greater than a second axial length of the sleeve. More particularly, the spear has a first ratio of cross-sectional area to weight that is less than a second ratio of cross-sectional area to weight of the sleeve.
To close off fluid communication when mated, the sleeve can define a seat in the passage toward the first proximal end. The seat can be configured to engage a portion of the second proximal end of the spear in a metal-to-metal seal, although other types of sealing arrangements can be used.
The second proximal end of the spear can include a head with a first outer dimension, while the second distal end of the spear can include a stem extending from the head and having a second outer dimension less than the head. The head can further define a bullet tip, while the stem can define a sharpened end. To stabilize engagement of the spear on a bumper downhole in the tubing, the head can have one or more landers disposed thereon.
In a plunger lift method for tubing in a well, the spear is deployed downhole in the tubing. The sleeve is deployed downhole in the tubing separate to the spear and allows fluid communication through the passage in the sleeve. Fluid communication is prevented through the passage in sleeve by inserting a distal end of the spear in the passage and mating a proximal end of the spear with the passage. Application of a pressure differential can then lift the mated sleeve and spear uphole in the tubing.
The method can involve catching the sleeve lifted uphole in the tubing and redeploying the sleeve downhole in the tubing by releasing the sleeve manually or automatically. The spear can be redeployed downhole in the tubing by unmating the spear from the sleeve lifted uphole in the tubing and permitting the spear to deploy downhole in the tubing before permitting the sleeve to deploy downhole.
Deploying the spear downhole in the tubing can involve permitting the spear to deploy at a faster rate downhole than the sleeve, although other arrangements are possible. Overall, the spear can be provided with a first weight greater than a second weight than the sleeve, with a first cross-sectional area that is greater than a second cross-sectional area of the sleeve, and with a first axial length greater than a second axial length of the sleeve. More particularly, to permit the spear to deploy at the faster rate downhole than the sleeve, the spear can be provided with a first ratio of cross-sectional area to weight that is less than a second ratio of cross-sectional area to weight of the sleeve.
The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A illustrates a plunger lift system according to the prior art.

FIG. 1B illustrates a partial cross-section of a two piece plunger according to the prior art.

FIG. 2 illustrates a partial cross-section of a conventional plunger according to the prior art.

FIGS. 3A-3B show side and cross-sectional views of a multi-sleeve plunger according to the prior art.

FIGS. 4A-4B illustrate a plunger lift system having a two-piece plunger according to the present disclosure during stages of operation.

FIGS. 5A-5B respectively illustrate a perspective view and a cross-sectional view of a sleeve and a spear of the disclosed plunger coupled together.

FIG. 6A illustrates a cross-sectional view of the sleeve of the disclosed plunger.

FIG. 6B illustrates a cross-sectional view of the spear of the disclosed plunger.

FIGS. 7A-7D illustrate cross-sectional views of various configurations of the disclosed plunger.

FIGS. 8A-8B illustrate a perspective view and an end view of the disclosed plunger having landers.

FIG. 9 illustrates a detail of a fishneck profile on the sleeve of the disclosed plunger.

DETAILED DESCRIPTION

A gas well in FIGS. 4A-4B has a plunger lift system 10 to handle the accumulation of formation liquid in the well. In an earlier stage of the well's productive life, a sufficient amount of gas may have been produced to deliver the formation liquids to the surface. However, due to the age of the well or other factors, the plunger lift system 10 may need to handle issues with liquid buildup in the well. In general, the plunger lift system 10 can lift oil, condensate, or water from the bottom of the well to the surface.
As shown, the well has production tubing 16 disposed in casing 14, which extend from a wellhead (not shown). Formation fluids enter the casing 14 via casing perforations 18. The produced fluids then enter the production tubing 16 and bypass a bottomhole bumper 20 positioned downhole. At the wellhead, a lubricator 30 routes produced fluids to a sales line.
A two-piece plunger 100 disposes in the tubing 16 and can move between the bumper 20 and the lubricator 30 to lift accumulated liquid to the surface. As shown briefly in FIGS. 4A-4B, the plunger 100 has a sleeve 110 and a separate spear 150. Being two pieces, the sleeve 110 and spear 150 are separate components that are disposed independently in the tubing. However, during aspects of operation, these two components 110/150 can fit together to complete the plunger 100. (Further details of the plunger 100 are provided later.)
Initially, the plunger 100 rests on the bottomhole bumper 20 toward the base of the well. When disposed at the bumper 20, the two components 110/150 mate together. As gas is produced through lines 32/34 on the lubricator 30, liquids may accumulate in the wellbore and create back-pressure that can slow gas production. Using sensors and the like, a controller 36 operates a valve 38 at the lubricator 30 to regulate the buildup of gas in the tubing 16. Sensing the slowing of gas production, the controller 36 shuts-in the well to increase pressure in the well as high-pressure gas begins to accumulate.
When sufficient gas volume and pressure level are reached, the gas pushes against the plunger 100 and eventually pushes the plunger 100 upward from the bumper 20 toward the lubricator 30 as illustrated in FIG. 4A. The column of liquid above the moving plunger 100 likewise moves up the tubing 16 so the liquid load can eventually be removed from the well at the surface. In this way, the plunger 100 essentially acts as a piston between liquid and gas in the tubing 16.
As the plunger 100 rises, the controller 36 allows gas and accumulated liquids above the plunger 100 to flow through the outlets 32/34. Eventually, the plunger 100 reaches the lubricator 30, and a spring 42 absorbs the plunger's impact. A catcher 40 on the lubricator 40 can then capture the plunger's sleeve 110 if desired. The spear 150 may be struck off from the sleeve 110 using a decoupler or striker rod (not shown) at the lubricator 30, or the spear 150 may simply be free to decouple on its own from the sleeve 110 in the absence of sufficient gas flow.
Meanwhile, the gas that lifted the plunger 100 flows through the lower outlet 32 to the sales line. Once the gas flow stabilizes, the controller 36 can shut-in the well and releases the sleeve 110, which drops back downhole to the bumper 20. Ultimately, the cycle can repeat itself.
As noted, the catcher 40 can hold the sleeve 110 and can control the release of the sleeve 110 to fall downhole after the spear 150. Yet, in some circumstances, using the catcher 40 to hold the sleeve 110 may not be required during a lift cycle. Instead, the sleeve 110 can be held in the lubricator 30 by the immediate uphole flow of gas during the lift cycle. This may occur for a sufficient amount of time after the spear 150 has descended into the well.
For its part, the spear 150 as shown in FIG. 4B is free to drop off the sleeve 110 when pressure fails to support it thereon. Thus, the spear 150 can promptly fall off the sleeve 110 and toward the bottom of the well when gas flow cannot support it coupled to the sleeve 110. Accordingly, a particular decoupler or striker rod may not be needed for this implementation to decouple the spear 150.
In general, the catcher 40 can have a conventional design when used. As shown in FIG. 4A, for example, the catcher 40 has a biased ball 44 that can latch onto the sleeve 110 and hold it. For example, the ball 44 can engage in grooves or detents of the sleeve's ribbing or in some other suitable profile or shoulder. In one implementation, the catcher 40 can be manually operated. As such, the catcher 40 can catch the sleeve 110 in the lubricator 30 so the sleeve 110 can be released manually by hand or can be retrieved and inspected as needed.
Alternatively, the catcher 40 can be automated. In such an auto catch assembly, the catcher 40 can automatically catch the plunger's sleeve 110 when it arrives at the surface during a lift cycle. A sensor (not shown) can be used to detect the plunger's arrival if necessary.
The controller 36 can then indicate when the sleeve 110 is to trip downhole rather than allowing the sleeve 110 to drop when the flow rate momentarily decreases. For such an automated catcher 40, a spring and piston arrangement 46 can bias a ball 44 on the catcher 40 using compressed gas from a source controlled by the controller 36. The pressure can be applied to a spring and piston arrangement 46 using diaphragm top works (not shown) or other device. With pressure applied, the ball 44 forces into the lubricator's pathway so the ball 44 can engage the plunge's sleeve 110. When appropriate, the controller 36 can then release gas pressure from the spring and piston arrangement 46. At this point, the weight of the sleeve 110 can push the ball 44 out of the way so the sleeve 110 is free to fall into the well.
The spear 150 drops first into the well either because it is not held by the catcher 40 (if present) and is free to fall with less restriction. In an alternative arrangement noted previously, a striker rod at the lubricator 30 could be used to dislodge the spear 150 using techniques known in the art. Once the spear 150 drops, the sleeve 110 follows in due course so the components 110/150 fall separately and independently of one another down the tubing 16. This enables the plunger 100 to fall faster downhole and with less restriction than other types of plungers. Once they reach bottom of the well, they unite and can eventually be lifted up to the surface to de-liquefy the gas well.
Because the spear 150 may fall promptly, it may fall while the well is still flowing. Thus, the spear 150 has a streamlined configuration allowing it to fall through higher flow rates. In particular, the spear 150 is elongated and has the form of a rod or stem with weighted bullet or head at its downhole end. With this configuration, the spear 150 can avoid issues encountered by dropped balls or the like and may be able to avoid friction issues and other problems when falling against flow. Nevertheless, the spear 150 is preferably designed to fall faster than the sleeve 110, although other arrangements are possible. Therefore, timing the dropping of the two components 110/150 may not be as much of an issue in the plunger lift system's operation as found in other systems.
When the separate components 110/150 reach the bottom of the well, they nest together in preparation for moving upwardly once pressure builds up. For example, the spear 150 falls into any liquid near the bottom and lands on the bumper 20. The sleeve 110 drops after the spear 150 to the bumper 20. When the sleeve 110 reaches the spear 150, they unite into a single component. Any gas entering the tubing 16 from the formation then starts to act against the bottom of the mated component 110/150 and can tend to push them together uphole. In this way, any new liquid above the mated components 110/150 can be forced uphole to the surface.
FIGS. 5A-5B respectively illustrate a perspective view and a cross-sectional view of the sleeve 110 and spear 150 of the disclosed plunger 100 coupled together. FIG. 6A illustrates a cross-sectional view of the sleeve 110 of the disclosed plunger 100 showing various dimensions, and FIG. 6B illustrates a cross-sectional view of the spear 150 of the disclosed plunger 100 showing various dimensions.
The sleeve 110 of the plunger 100 has a cylindrical body with an external surface 120 and defines a central passage 112 from a proximal end 114 to a distal end 116. (In context, the proximal end 114 is the downhole end oriented downhole from the midpoint, middle, center, etc. of the sleeve 110, while the distal end 116 is the uphole end oriented uphole of the sleeve's midpoint.) The exterior of the sleeve 110 can have ribbing 120 for creating a pressure differential across the sleeve 110 when disposed in tubing. The ribbing 120 may be of any suitable type, including wire windings or a series of grooves or indentations. The ribbing 120 creates a turbulent zone between the sleeve 110 and the inside of the producing tubing, which restricts liquid flow on the outside of the sleeve 110. The ribbing 120 can also be used as a catch area for holding the sleeve 110 at the wellhead.
Although the sleeve's exterior is shown having ribbing 120, other features can be used to create a pressure differential across the sleeve 110 when disposed in tubing. For example, the sleeve 110 can have fixed brushes, biased T-pads, or other known components for creating the pressure differential.
The spear 150 of the plunger 100 also has a proximal end 152 and a distal end 154. (In context, the proximal end 152 is the downhole end oriented downhole from the midpoint, middle, center, etc. of the spear 150, while the distal end 154 is the uphole end oriented uphole of the spear's midpoint.) As already noted, the spear 150 is elongated, including a bullet or head at the proximal end 152 and including a rod or stem 154 extending from the head 152 along the length of the spear 150 to the distal end 154. Contrary to the exterior of the sleeve 110, the spear 150 has a smooth exterior surface. The head 152 has a bullet contour 153 to facilitate its passage downhole through gas flow in the tubing. The very tip of the head 152 may be flattened where the head 152 engages the components of the downhole bumper (not shown).
When the sleeve 110 and spear 150 are coupled together, the stem 154 of the spear 140 at least partially installs in the passage 112 of the sleeve 110. (In fact, the stem 154 with its smaller outer dimension can substantially fit inside the sleeve's passage 112 so that the stem 154 extends at least three-fourths of the length or more of the sleeve's passage 112.) The head 152 of the spear 150, which may encompass about one-third or less of the length of the spear 150, at least partially mates with the proximal end 114 of the sleeve 110, and the spear 150 at least partially closes fluid communication through the passage 112 of the sleeve 110 when mated therewith.
In particular, the passage 112 of the sleeve 110 defines a seat or restriction 118 toward the sleeve's proximal end 114. The head 152 of the spear 150 defines a transition 158 from a larger diameter (D5) to a narrower diameter (D4) of the stem 154. A sharpened end 155 of the stem 154 at the distal (uphole) end of the spear 150 can facilitate insertion of the stem 154 into the passage 112. When the stem 154 inserts inside the sleeve's passage 112, the transition 158 mates with the seat 118 to close off fluid flow through the passage 112. As shown here, the transition 158 is preferably smooth and contoured in accordance with the rest of the spear 150. This is not strictly necessary since a sharper transition or shoulder could be used.
As will be appreciated, the surface areas of the components 110/150 against which flow acts, the weight of the components 110/150, their diameters, and other variables can be designed for a particular implementation and can depend on several factors, such as the size of the production tubing, expected gas flow, formation fluid properties, etc. Some exemplary dimensions are provided here for illustrative purposes.
When used for 2⅜-in tubing that can have an internal dimension of about 1.995-in, the overall length (L1) of the sleeve 110 can be 6-in, and the overall diameter (D1) of the sleeve 110 can be 1.9-in. The inside diameter (D2) of the bore 112 can be about 1.5-in., and the bore's seat 118 can have an inside diameter (D3) of about 1.2-in.
The overall length (L2) of the spear 150 can be 6.5-in. As will be appreciated, the spear's length (L2) as compared to the diameter of the tubing is sufficient that the spear 150 does not flip over, rotate end-to-end, or lodge during passage along the tubing. The overall diameter (D4) of the spear's rod 154 can be 1.0-in, while the diameter of the head 152 can be 1.2-in at its maximum. The rod 154 can encompass about 4.3-in of the spear's length, while the head 152 can make up the remainder of about 2.2-in. When the head 152 seats against the seat 118 of the sleeve's bore 112, the engagement can be made roughly at about 1.35-in. in diameter.
With these dimensions and with a standard steel density of about 0.283-lb/in³, the spear 150 has a weight of about 1.65-lbs, whereas the sleeve 110 has a weight of about 1.61-lbs. The cross-sectional area of the sleeve 110 is about 1.404-in², while the cross-sectional area of the spear 150 is about 1.431-in². (Cross-sectional area as discussed herein refers to the area responsible for generating force under pressure.) Thus, the ratio of the cross-section area to the weight for the sleeve 110 is higher than that of the spear 150. In the current example, the sleeve 110 has an area-to-weight ratio of about 0.872-in²/lb, and the spear 150 has a ratio of about 0.867-in²/lb. This makes the sleeve's ratio about 0.5% greater than the spear 150.
As will be appreciated, the above dimensions, weights, ratios, and the like can be scaled for other implementations with different tubing sizes, such as 2 1/16, 2⅞, and 3½-in. Similarly, the above dimensions, weights, ratios, and the like can be adjusted accordingly to accommodate flow rates, fluid content, and other factors of a well.
In this regard, the overall length of the sleeve 110 and spear 150 can be adjusted either alone or together to alter the weight, ratios, and dimensions of the plunger 100 for a particular implementation. In this way, even for a given tubing size (e.g., the 2⅜-in discussed above), the lengths of the sleeve 110 and spear 150 can be adjusted to produce desired weights and ratios to meet the needs of the particular well, flow rates, and other variables encountered.
For example, FIGS. 7A-7D show various configurations of the plunger 100A-D. FIGS. 7A-7D show the plunger 100A-D with longer designs compared to the previous plunger of FIG. 5B. The plunger 100A in FIG. 7A has the sleeve 110 extending 8-in. and has the spear 150 extending about 9.2-in. The radial dimensions and cross-sectional areas of the sleeve 110 and spear 150 can be relatively the same as before due to the comparable tubing size, and the same materials can be used. The different overall lengths of the sleeve 110 and spear 150, however, alter the weight of these components. Here, the sleeve 110 can weigh about 2.06-Ib, while the spear 150 can weigh about 2.32-lb. Thus, the area-to-weight ratio for the sleeve 110 can be 0.682-in²/lb and can be 0.617-in²/lb for the spear 150. This makes the sleeve's ratio 10.5% greater than the spear 150.
As shown in FIG. 7B, the plunger 100B is shown in an even longer design with the sleeve 110 extending 10-in. and the spear 150 extending about 11.2-in. The radial dimensions and cross-sectional areas of the sleeve 110 and spear 150 can be relatively the same as before due to the comparable tubing size, and the same materials can be used. Here, the sleeve 110 can weigh about 2.54-Ib, while the spear 150 can weigh about 2.76-lb. Thus, the area-to-weight ratio for the sleeve 110 can be 0.553-in²/lb and can be 0.518-in²/lb for the spear 150. This makes the sleeve's ratio 6.7% greater than the spear 150.
As shown in FIG. 7C, the plunger 100C is shown in an even longer design with the sleeve 110 extending 12-in. and the spear 150 extending about 13.2-in. The radial dimensions and cross-sectional areas of the sleeve 110 and spear 150 can be relatively the same as before due to the comparable tubing size, and the same materials can be used. Here, the sleeve 110 can weigh about 3.0-Ib, while the spear 150 can weigh about 3.2-lb. Thus, the area-to-weight ratio for the sleeve 110 can be 0.468-in²/lb and can be 0.447-in²/lb for the spear 150. This makes the sleeve's ratio 4.7% greater than the spear 150.
As shown in FIG. 7D, the plunger 100D has the spear 150 extending a greater length through the sleeve 110. Here, the proximal end 152 of the spear 150 extends beyond the proximal end 114 of the sleeve 110, and the distal end 154 of the spear 150 extends beyond the distal end 116 of the sleeve 110. In one advantage when the combined sleeve 110 and spear 150 arrives at top of the lubricator (30), the distal end 154 of the elongated spear 150 engages a strike pad of the lubricator (30). This knocks the spear 150 free of the sleeve 110 so the spear 150 can start its downward journey. This arrangement of the longer spear 150 can be used with any of the various sizes and configurations of the plunger 100 disclosed herein. As shown in this embodiment and as is possible in others, the distal end 154 of the spear 150 can further include a fishneck head or the like to assist with potential retrieval if necessary.
As shown in FIGS. 7A-7D, the stem 154 can substantially fit inside the sleeve's passage 112 so that the stem 154 extends almost the entire length of the sleeve's passage 112. As also shown, the spear's head 152 may encompass about one-quarter, one-fifth, or less of the length of the spear 150. Thus, when the spear 150 mates with the sleeve 110, the stem 154 mostly completes the sleeve's passage 112, and the less extensive head 152 at the proximal end of the spear 150 mates with the proximal end 114 of the sleeve 110. In this sense, the spear 150 and sleeve 110 mate to form a solid type of plunger body with a length comparable to the sleeve 110. Yet, when unmated, the spear 150 and sleeve 110 are subject to different cross-sectional area to weight ratios that can be beneficially configured for a given implementation.
Further alteration of the ratios can be achieved by altering the materials used for the sleeve 110 and/or the spear 150. Although the above examples show that increased length of one component (e.g., sleeve 110) equates to a comparable increase in length of the other component (e.g., spear 150), this is not strictly necessary. It is possible in other configurations that the length of one component may be disproportionate to the other component.
As previously depicted, landers 156 can be disposed on the head 152 of the spear 150 to stabilize the spear 150 when landed on the bumper (20). Further details of the landers 156 are shown in FIGS. 8A-8B. The landers 156 can be protrusions, fins, tabs, or legs disposed about the head 152 to help hold the spear 150 upright in the tubing (16) and mate with the sleeve 110.
As previously depicted, a fishneck profile 115 can be provided inside the distal end of the sleeve 110. Further details of the fishneck profile 115 are shown in FIG. 9. The fishneck profile 115 can allow the sleeve 110 to be retrieved using standard fishing techniques. The spear 150 may need to be retrieved in other ways using a grabbing tool, for example.
The sleeve 110 and spear 150 of the disclosed plunger 100 have been depicted without seals. Use of a seal may be unnecessary for at least partially closing off fluid communication between the sleeve 110 and the spear 150 when mated together. However, it will be appreciated that one or more seals may be used on the sleeve 110 and spear 150. For example, one or more seals can be used on the abutting surfaces between the sleeve's seat 118 and the spear's transition 138 so as not to interfere with the free decoupling between the sleeve 110 and spear 150.
The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. It will be appreciated with the benefit of the present disclosure that features described above in accordance with any embodiment or aspect of the disclosed subject matter can be utilized, either alone or in combination, with any other described feature, in any other embodiment or aspect of the disclosed subject matter.
In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof.

Claims

What is claimed is:

1. A plunger lift apparatus for tubing in a well, comprising:

a sleeve for disposing in the tubing, the sleeve defining a passage therethrough from a first proximal end to a first distal end; and

a spear for disposing in the tubing downhole of the sleeve, the spear being elongated and extending from a second proximal end to a second distal end, the second distal end of the spear inserting in the passage of the sleeve, the second proximal end of the spear mating with the first proximal end of the sleeve, the spear at least partially closing fluid communication through the passage of the sleeve when mated therewith.

2. The apparatus of claim 1, wherein the sleeve comprises means for producing a pressure differential across the sleeve.

3. The apparatus of claim 1, wherein the sleeve and the spear mated together move uphole within the tubing by application of a pressure differential.

4. The apparatus of claim 1, wherein the spear deploys at a faster rate downhole in the tubing than the sleeve.

5. The apparatus of claim 1, wherein the spear comprises a first weight greater than a second weight than the sleeve.

6. The apparatus of claim 1, wherein the spear comprises a first cross-sectional area that is greater than a second cross-sectional area of the sleeve.

7. The apparatus of claim 1, wherein the spear comprises a first axial length greater than a second axial length of the sleeve.

8. The apparatus of claim 7, wherein the second distal end of the spear extends beyond the first distal end of the sleeve and the second proximal end of the spear extends beyond the first proximal end of the sleeve when the spear is mated with the sleeve.

9. The apparatus of claim 1, wherein the spear comprises a first ratio of cross-sectional area to weight that is less than a second ratio of cross-sectional area to weight of the sleeve.

10. The apparatus of claim 1, wherein the sleeve defines a seat in the passage toward the first proximal end, the seat configured to engage a portion of the second proximal end of the spear.

11. The apparatus of claim 1, wherein the second proximal end of the spear comprises a head, and wherein the second distal end of the spear comprises a stem extending from the head.

12. The apparatus of claim 11, wherein the head defines a bullet tip, and wherein the stem defines a sharpened end.

13. The apparatus of claim 11, wherein the head comprises one or more landers disposed thereon and stabilizing engagement of the spear downhole in the tubing.

14. The apparatus of claim 11, wherein the head comprises a first outer dimension being greater than a second outer dimension of the stem, a portion of the first outer dimension of the head being configured to engage a portion of the passage of the sleeve toward the first proximal end.

15. The apparatus of claim 1,

wherein the passage of the sleeve has a first proximal opening toward the first proximal end and has a first distal opening toward the first distal end;

wherein the second distal end of the spear installs through the first proximal opening; and

wherein the second proximal end of the spear at least partially mates at the first proximal opening of the passage.

16. The apparatus of claim 1, further comprising a catcher disposed uphole of the tubing and operable to engage the sleeve.

17. The apparatus of claim 16, further comprising a controller operably coupled to the catcher and controlling engagement of the catcher with the sleeve.

18. The apparatus of claim 1, further comprising:

a valve in fluid communication with the tubing; and

a controller operably coupled to the valve and controlling the valve in response to a condition in the tubing.

19. The apparatus of claim 1, wherein the second distal end of the spear is longer than the second proximal end.

20. A plunger lift apparatus for tubing in a well, comprising:

a sleeve for disposing in the tubing, the sleeve defining a passage therethrough; and

a spear for disposing in the tubing downhole of the sleeve, the spear mating with the sleeve downhole and at least partially closing fluid communication through the passage of the sleeve when mated therewith, the spear deploying at a faster rate downhole in the tubing than the sleeve.

21. A plunger lift apparatus for tubing in a well, comprising:

a sleeve for disposing in the tubing, the sleeve defining a passage therethrough and having a first ratio of cross-sectional area to weight; and

a spear for disposing in the tubing downhole of the sleeve, the spear mating with the sleeve downhole and at least partially closing fluid communication through the passage of the sleeve when mated therewith, the spear having a second ratio of cross-sectional area to weight being less than the first ratio of the sleeve.

22. The apparatus of claim 21, wherein the cross-sectional area comprises an effective area responsible for force generated under differential pressure.

23. A plunger lift method for tubing in a well, comprising:

deploying a spear with a first ratio of cross-sectional area to weight downhole in the tubing;

deploying a sleeve with a second ratio of cross-sectional area to weight downhole in the tubing separate to the spear by allowing fluid communication through a passage in the sleeve;

preventing fluid communication through the passage in the sleeve by inserting a distal end of the spear in the passage and mating a proximal end of the spear with the passage; and

lifting the mated sleeve and spear uphole in the tubing by application of a pressure differential.

24. The method of claim 23, further comprising catching the sleeve lifted uphole in the tubing.

25. The method of claim 24, further comprising redeploying the sleeve downhole in the tubing by releasing the sleeve manually or automatically.

26. The method of claim 23, further comprising redeploying the spear downhole in the tubing by unmating the spear from the sleeve lifted uphole in the tubing.

27. The method of claim 26, wherein redeploying the spear comprises permitting the spear to deploy downhole in the tubing before permitting the sleeve to deploy downhole.

28. The method of claim 23, wherein deploying the spear downhole in the tubing comprises permitting the spear to deploy at a faster rate downhole than the sleeve.

29. The apparatus of claim 28, wherein permitting the spear to deploy at the faster rate downhole than the sleeve comprises providing the spear with one or more of:

a first weight greater than a second weight than the sleeve;

a first cross-sectional area that is greater than a second cross-sectional area of the sleeve;

a first axial length greater than a second axial length of the sleeve; and

the first ratio of cross-sectional area to weight that is less than the second ratio of cross-sectional area to weight of the sleeve.