Patent Application
20160090827
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
The plunger 50A shown in
The two-piece plunger 50A of
When used in the system 10 of
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
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.
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.
A gas well in
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
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
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
In general, the catcher 40 can have a conventional design when used. As shown in
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.
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,
As shown in
As shown in
As shown in
As shown in
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
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
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.
