CA2315730C - Centralizer for sucker rod strings - Google Patents
Centralizer for sucker rod strings Download PDFInfo
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- CA2315730C CA2315730C CA 2315730 CA2315730A CA2315730C CA 2315730 C CA2315730 C CA 2315730C CA 2315730 CA2315730 CA 2315730 CA 2315730 A CA2315730 A CA 2315730A CA 2315730 C CA2315730 C CA 2315730C
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- centralizer
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- sucker rod
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Abstract
A centralizer for sucker rod strings is disclosed. The invention has particular use for centralizing sucker rods in a tubing string in connection with a downhole rotary pump driven by a rotating rod string. The single piece, double box centralizer has internally threaded ends for attachment to the threaded pin ends of sucker rod string components. A central shaft portion of the centralizer has a reduced diameter over which a centralizer sleeve is placed. The sleeve is kept in place by shoulders of the larger diameter ends of the centralizer. The centralizer sleeve may be a single piece snap-on type made of a flexible material, or the sleeve can be made up of two or more pieces which snap together.
Description
Centralizer for Sucker Rod Strings Field of the Invention The invention relates to a centralizer apparatus for sucker rod strings. In particular, the invention relates to a centralizer for rotating rod strings driving a downhole rotary pump.
Background of the Invention Wells for the production of fluid hydrocarbons, such as oil, in the vast majority of cases require the use of a downhole pump. The use of a downhole pump is essential in situations where the fluid is of high viscosity, or where there is relatively low well pressure. Once a well has been drilled, a production tubing string is directed down the well as a conduit for the removal of the heavy oil from the reservoir. This tubing string consists of successive lengths of metal tubing which are lowered into the borehole and threaded together to form a continuous tubing.
Down hole pumps are generally either mounted in or attached to the bottom end of the production tubing. The pumps are operated by a sucker rod string extending through the tubing. The sucker rod string, like the tubing string, is made up of successive lengths, called sucker rods, which can be connected end to end. Each sucker rod is typically a solid cylindrical shaft of about 25 - 30 feet in length, and has a diameter of about 0.75 inches. Unlike the tubing string sections, the sucker rods have dual threaded pin ends. In order to interconnect two sucker rods end to end, the industry standard is to use a sucker rod coupling. This coupling is a cylindrical internally threaded member, with an outside diameter greater than the outside diameter of the sucker rods. A typical sucker rod coupling has an outside diameter of 1.875 inches.
The role of the sucker rod string is to actuate the downhole pump. Two principal approaches to actuation of the downhole pump using a sucker rod string are known: a reciprocating motion of the rod string or a rotating motion. In both types of operation, but particularly in the latter, solid material, e.g. sand, can be
Background of the Invention Wells for the production of fluid hydrocarbons, such as oil, in the vast majority of cases require the use of a downhole pump. The use of a downhole pump is essential in situations where the fluid is of high viscosity, or where there is relatively low well pressure. Once a well has been drilled, a production tubing string is directed down the well as a conduit for the removal of the heavy oil from the reservoir. This tubing string consists of successive lengths of metal tubing which are lowered into the borehole and threaded together to form a continuous tubing.
Down hole pumps are generally either mounted in or attached to the bottom end of the production tubing. The pumps are operated by a sucker rod string extending through the tubing. The sucker rod string, like the tubing string, is made up of successive lengths, called sucker rods, which can be connected end to end. Each sucker rod is typically a solid cylindrical shaft of about 25 - 30 feet in length, and has a diameter of about 0.75 inches. Unlike the tubing string sections, the sucker rods have dual threaded pin ends. In order to interconnect two sucker rods end to end, the industry standard is to use a sucker rod coupling. This coupling is a cylindrical internally threaded member, with an outside diameter greater than the outside diameter of the sucker rods. A typical sucker rod coupling has an outside diameter of 1.875 inches.
The role of the sucker rod string is to actuate the downhole pump. Two principal approaches to actuation of the downhole pump using a sucker rod string are known: a reciprocating motion of the rod string or a rotating motion. In both types of operation, but particularly in the latter, solid material, e.g. sand, can be
-2-removed from the well suspended in the fluid being pumped. The particulate material leads to wear on the surfaces to which it is exposed, i.e. the outside of the sucker rod string, and the interior of the tubing string. This wear problem is compounded in deviated wells with well bores of angular, curved or deflected orientation.
Current development of heavy oil fields or reservoirs commonly involves several wells placed close together from a single "pad".
Since several wells are typically drilled from this central "pad", a number of the wells must be bored in and produced from different directions. Those wells with angled well bores are called angular or deviated wells. Especially in angular wells, the sucker rod string often assumes a curvilinear shape inside the tubing string, and as a result of the tension in the sucker rods, tends to be pulled into the inside curve of the tubing string. As a result of this bowing, the movement of the sucker rod string to actuate the downhole pump leads to rubbing or slapping of the sucker rod string against the tubing string. This leads to excessive wear of both components. Hard particulates, such as sand, in the pumped fluid can then get trapped between the sucker rod string and the tubing string leading to abrasion of these parts. As the sucker rod coupling has a larger outside diameter than the sucker rods, the wear is concentrated at those points in the tubing string corresponding to the position of the sucker rod coupling in the sucker rod string. The wear on the tubing string can lead to erosion of the wall of the tubing string with a consequential detrimental impact on the production from the well, and the need for costly repairs.
This wear problem is well known in the industry and commonly a centralizes device is used to keep the sucker rod string coupling spaced apart from the wall of the tubing string. U.S. Patent No.
4,913,230 by Rivas et al. discloses a centralizes for a reciprocating sucker rod, which centralizes includes internally threaded box ends for connection with the externally threaded pin
Current development of heavy oil fields or reservoirs commonly involves several wells placed close together from a single "pad".
Since several wells are typically drilled from this central "pad", a number of the wells must be bored in and produced from different directions. Those wells with angled well bores are called angular or deviated wells. Especially in angular wells, the sucker rod string often assumes a curvilinear shape inside the tubing string, and as a result of the tension in the sucker rods, tends to be pulled into the inside curve of the tubing string. As a result of this bowing, the movement of the sucker rod string to actuate the downhole pump leads to rubbing or slapping of the sucker rod string against the tubing string. This leads to excessive wear of both components. Hard particulates, such as sand, in the pumped fluid can then get trapped between the sucker rod string and the tubing string leading to abrasion of these parts. As the sucker rod coupling has a larger outside diameter than the sucker rods, the wear is concentrated at those points in the tubing string corresponding to the position of the sucker rod coupling in the sucker rod string. The wear on the tubing string can lead to erosion of the wall of the tubing string with a consequential detrimental impact on the production from the well, and the need for costly repairs.
This wear problem is well known in the industry and commonly a centralizes device is used to keep the sucker rod string coupling spaced apart from the wall of the tubing string. U.S. Patent No.
4,913,230 by Rivas et al. discloses a centralizes for a reciprocating sucker rod, which centralizes includes internally threaded box ends for connection with the externally threaded pin
-3-ends of the sucker rods. U.S. Patent No. 5,247,990 by Sudol et al.
describes centralizer sleeves for mounting directly onto a sucker rod either by sliding thereon or by installing it on the rod in the field, whereby the centralizer is manufactured in two or more pieces for field assembly. These centralizers are for use with reciprocating sucker rods and are mounted on the sucker rods themselves rather than a sucker rod coupling. The disadvantage of such centralizers is that any wear is directly on the sucker rod body component, leading to premature weakness of the sucker rod string.
One way in which the disadvantage of wear on the sucker rod has been overcome is to provide a sucker rod centralizer which is placed at the connections of the sucker rods. U.S. Patent No.
describes centralizer sleeves for mounting directly onto a sucker rod either by sliding thereon or by installing it on the rod in the field, whereby the centralizer is manufactured in two or more pieces for field assembly. These centralizers are for use with reciprocating sucker rods and are mounted on the sucker rods themselves rather than a sucker rod coupling. The disadvantage of such centralizers is that any wear is directly on the sucker rod body component, leading to premature weakness of the sucker rod string.
One way in which the disadvantage of wear on the sucker rod has been overcome is to provide a sucker rod centralizer which is placed at the connections of the sucker rods. U.S. Patent No.
4,905,760 by Kenneth Gray, shows a common sucker rod coupling which is machined to have a decreased external diameter and is provided with an external, fusion bonded, resinous coating to impart abrasion resistance and extend the service life of the coupling.
U.S. Patent No. 4,757,861 by Albert A. Klyne discloses a sucker rod coupling centralizer assembly. The Klyne patent discloses a centralizer shaft with double pin ends and a tubular centralizer sleeve which can slide over the centralizer shaft. The centralizer shaft is connected to the sucker rod string using a sucker rod coupling at each end of the centralizer shaft, such that the sucker rod coupling outer diameter is greater than the outer diameter of the centralizer shaft and the inner diameter of the centralizer sleeve. This increases cost, since two rod couplings are needed for each sucker rod connection rather than one as in conventional assemblies. Klyne also teaches an improvement over the basic design wherein the end surfaces of the rod couplings engaging the centralizer sleeve and the centralizer body are coated with an abrasion resistant material to improve the service life of the centralizer. U.S. Patent No. 4,919,202 of Carl Clintberg describes a similar centralizer arrangement wherein the only difference is the presence of torque washers between the centralizer sleeve and the sucker rod couplings, which washers act as sacrificial wear surfaces. Bearing shoulders for the torque transfer washers are created by practically recessing the centralizer sleeve into the centralized shaft. U.S. Patent No. 5,261,498 of Steinkamp et al.
discloses a drill string centralizer which is basically of the same principle construction as the sucker rod centralizers of Klyne and Clintberg. All of these centralizers have the disadvantage that the centralizer shaft is of reduced cross-section at the connection with the sucker rod pin ends, creating a weak point.
It is now an object of the current invention to provide a centralizer assembly which overcomes the problems encountered with the prior art centralizers, combines the centralizer and rod coupling functions into one centralizer and which allows the centralizer shaft to be of smaller diameter thereby facilitating centralizer sleeves of larger shell thickness which can be field mounted.
Summary of the Invention Accordingly, the present invention provides a sucker rod centralizer for coupling and centralizing sucker rods wherein the coupling has a pair of terminal box ends internally threaded for attachment to a threaded pin end of a sucker rod string component, a shaft extending between the box ends and having a smaller outside diameter than the outer diameter of the terminal box ends, and a centralizer sleeve for fittingly and slidingly engaging an outer surface of the shaft, the outer diameter of the sleeve being larger than the outer diameter of the box ends.
In a preferred embodiment, the centralizer coupling has a single dumbell-shaped body over which the centralizer sleeve can be placed in the field.
Brief Description of the Drawings Fig. 1 is a side view of a preferred embodiment in accordance with the invention.
U.S. Patent No. 4,757,861 by Albert A. Klyne discloses a sucker rod coupling centralizer assembly. The Klyne patent discloses a centralizer shaft with double pin ends and a tubular centralizer sleeve which can slide over the centralizer shaft. The centralizer shaft is connected to the sucker rod string using a sucker rod coupling at each end of the centralizer shaft, such that the sucker rod coupling outer diameter is greater than the outer diameter of the centralizer shaft and the inner diameter of the centralizer sleeve. This increases cost, since two rod couplings are needed for each sucker rod connection rather than one as in conventional assemblies. Klyne also teaches an improvement over the basic design wherein the end surfaces of the rod couplings engaging the centralizer sleeve and the centralizer body are coated with an abrasion resistant material to improve the service life of the centralizer. U.S. Patent No. 4,919,202 of Carl Clintberg describes a similar centralizer arrangement wherein the only difference is the presence of torque washers between the centralizer sleeve and the sucker rod couplings, which washers act as sacrificial wear surfaces. Bearing shoulders for the torque transfer washers are created by practically recessing the centralizer sleeve into the centralized shaft. U.S. Patent No. 5,261,498 of Steinkamp et al.
discloses a drill string centralizer which is basically of the same principle construction as the sucker rod centralizers of Klyne and Clintberg. All of these centralizers have the disadvantage that the centralizer shaft is of reduced cross-section at the connection with the sucker rod pin ends, creating a weak point.
It is now an object of the current invention to provide a centralizer assembly which overcomes the problems encountered with the prior art centralizers, combines the centralizer and rod coupling functions into one centralizer and which allows the centralizer shaft to be of smaller diameter thereby facilitating centralizer sleeves of larger shell thickness which can be field mounted.
Summary of the Invention Accordingly, the present invention provides a sucker rod centralizer for coupling and centralizing sucker rods wherein the coupling has a pair of terminal box ends internally threaded for attachment to a threaded pin end of a sucker rod string component, a shaft extending between the box ends and having a smaller outside diameter than the outer diameter of the terminal box ends, and a centralizer sleeve for fittingly and slidingly engaging an outer surface of the shaft, the outer diameter of the sleeve being larger than the outer diameter of the box ends.
In a preferred embodiment, the centralizer coupling has a single dumbell-shaped body over which the centralizer sleeve can be placed in the field.
Brief Description of the Drawings Fig. 1 is a side view of a preferred embodiment in accordance with the invention.
-5-Fig. 2 is a semi-isometric view of the embodiment shown in Figure 1.
Fig. 3 is an exploded view of the embodiment shown in Figure 1.
Fig. 4 is an end view of the embodiment shown in Figure 1.
Fig. 5 is a semi isometric view of a second preferred embodiment including a slitted centralizer sleeve.
Detailed description of the Preferred Embodiment The preferred embodiment of a centralizer coupling according to the invention is shown in Figure 1. In this embodiment the centralizer 10 is of a dumbell shape including a pair of cylindrical box ends 12, a shaft 14 extending therebetween and a centralizer sleeve 11 mounted in its operational position on the shaft. Each box end 12 of the centralizer 10 has a greater outside diameter than both the shaft 14 and the sucker rod to which it will be attached as further described below. A centralizer sleeve stop shoulder 15 is created at each juncture of the shaft 14 with the box ends 12 due to the smaller outer diameter of the shaft 14 relative to the ends.
Figure 2 more clearly illustrates the structure of the integral box ends 12. Each coupling end 12 is provided with an axial internally threaded bore 16 for engagement with the threaded pin end of a sucker rod (not shown). The dimensions of the thread of the internally threaded bore 16 are matched to those of the sucker rod pin ends. To increase the strength of the centralizer, the box ends 12 are longer than the internally threaded bore 16 which extends only partially into each box end 12. Furthermore, the length of the bore 16 is greater than the maximum insertion depth of the sucker rod pin ends. The unitary design of the box ends 12 at the shaft 14 provides a centralizer shaft of greater strength and a centralizer which can be manufactured at a lower cost than conventional double pin shaft couplings.
In a preferred embodiment, the shaft 14 is approximately the same length as the box ends 12. The diameter and length of the box
Fig. 3 is an exploded view of the embodiment shown in Figure 1.
Fig. 4 is an end view of the embodiment shown in Figure 1.
Fig. 5 is a semi isometric view of a second preferred embodiment including a slitted centralizer sleeve.
Detailed description of the Preferred Embodiment The preferred embodiment of a centralizer coupling according to the invention is shown in Figure 1. In this embodiment the centralizer 10 is of a dumbell shape including a pair of cylindrical box ends 12, a shaft 14 extending therebetween and a centralizer sleeve 11 mounted in its operational position on the shaft. Each box end 12 of the centralizer 10 has a greater outside diameter than both the shaft 14 and the sucker rod to which it will be attached as further described below. A centralizer sleeve stop shoulder 15 is created at each juncture of the shaft 14 with the box ends 12 due to the smaller outer diameter of the shaft 14 relative to the ends.
Figure 2 more clearly illustrates the structure of the integral box ends 12. Each coupling end 12 is provided with an axial internally threaded bore 16 for engagement with the threaded pin end of a sucker rod (not shown). The dimensions of the thread of the internally threaded bore 16 are matched to those of the sucker rod pin ends. To increase the strength of the centralizer, the box ends 12 are longer than the internally threaded bore 16 which extends only partially into each box end 12. Furthermore, the length of the bore 16 is greater than the maximum insertion depth of the sucker rod pin ends. The unitary design of the box ends 12 at the shaft 14 provides a centralizer shaft of greater strength and a centralizer which can be manufactured at a lower cost than conventional double pin shaft couplings.
In a preferred embodiment, the shaft 14 is approximately the same length as the box ends 12. The diameter and length of the box
-6-ends 12 are the same as that of an API standard "regular" sucker rod coupling for the size of sucker rods to which they will be attached. The box ends 12 are bored and tapped to ~ the length.
The outside diameter of the shaft 14 is less than the outside diameter of the box ends 12. It can be even less than the diameter of the internally threaded bore 16 in which case the solid, unthreaded portion of the box ends 12 is extended in axial direction to provide added strength at the juncture of the shaft with the box ends. It is over this shaft 14, and between the end shoulders 15 of the box ends that the centralizer sleeve is positioned. The reduced diameter of the shaft 14 allows the use of a centralizer sleeve 11 of greater shell thickness which in turn translates into greater centralizer sleeve strength.
The exploded view of Figure 3 illustrates how the centralizer sleeve 11 fits over the box ends 12 in the preferred embodiment of the invention. In the embodiment illustrated, the centralizer sleeve 11 is split along an axial plane into a pair of sleeve portions 17 and 18, which in this embodiment are made of a hard wearing material such as Kevlar°. The sleeve portions are provided with interlocking structures for connecting them. Preferably, the first sleeve portion 17 has a locking tongue 19 running the length of each of the lateral edges of the first portion 17. This locking tongue 19 is complementary in shape to a longitudinal locking groove 20 which runs the length of each of the lateral edges of the second portion 18. In operation, the first and second centralizer sleeve portions 17, 18 are interlocked by the complementary tongues 19 and grooves 20 to form a cylindrical centralizer sleeve 11 that fits over the shaft 14. The inner diameter of the centralizer sleeve 11 is less than the outer diameter of the coupling ends 12 to prevent the centralizer sleeve sliding off the shaft 14 over one of the coupling ends. The sleeve 11 preferably slidably closely fits over the shaft 14 to prevent wobble of the sleeve relative to the shaft during rotation of the sucker rod string. The outer diameter of the centralizer sleeve 11 is larger than the outer diameter of the box ends 12 to prevent contact thereof with the production tubing which would result in wear of the box ends and the tubing.
In the preferred embodiment, the centralizer sleeve 11 consists of a tubular body 21 which in the assembled condition continuously surrounds the shaft 14. The wall thickness of the tubular body 21 is a principle determinant of the strength of the sleeve 11.
Integral to the centralizer sleeve 11, and on the outer surface thereof, are a series of spaced apart spacer fins 22 which maintain the necessary spacing between the centralizer sleeve and the production tubing to permit passage of the well fluid being pumped.
The height of the spacer fins 22 is substantially equal to the distance between the surface of the body 21 and the inner diameter of the production tubing. Thus, the height of the spacer fins 22 is determined by the diameter of the tubing, the diameter of the sleeve, and the desired volume of the annular space between the sleeve body and the tubing.
The spacer fins 22 in the illustrated embodiment are straight and extend parallel to the axis of the sleeve 11. However, for applications of the centralizer with reciprocating strings, they may also be positioned at an angle to the axis or may be curved.
The centralizer sleeve remains stationary and the sucker rod string rotates inside of it. Therefore, the centralizer assembly operates as a bearing. Curved spacer fins provide slightly better stand-off, but the advantage is slight and the disadvantage is a higher pressure drop.
The extension of the spacer fins 22 above the outer diameter of the box ends 12 is more clearly illustrated in Figure 4. The spacer fins 22 are preferably of trapezoid cross-section to reduce wear on the production tube but can be of rectangular, square or rounded cross-section.
_g_ In another preferred embodiment, the centralizer sleeve 11 consists of a single part. As illustrated in Figure 5, the single-piece centralizer sleeve 11 includes a slit 24 which runs the length of the centralizer sleeve 11 and allows the sleeve 11 to be forced open for sliding over the shaft 14 or one of the box ends 12 for installation onto the shaft. The slit is preferably placed at an angle to the axis of the sleeve to provide the sleeve with greater flexibility, but can be positioned parallel thereto or of helical shape. The sleeve 11 is preferably made of a flexible plastic material, such as Nylon°. Materials which are flexible and have good abrasion resistance may also be advantageously used, for example Teflon~. In both of the above embodiments the centralizer sleeve 11 can be replaced while the centralizer coupling 10 is incorporated in a sucker rod string (not illustrated).
In order to reduce wear of the stop shoulders 15, the shaft 14 and the centralizer sleeve 11, the wear surfaces of the stop shoulders 15 and the shaft 14 are chrome plated. The preferred materials used for the centralizer sleeves are usually resistant to abrasion and therefore it is generally the shaft 14 which is subjected to the most wear if not protected by a hard surface. Thus the shaft 14 is preferably provided with a hardened or hard coated surface. A hard facing of the shaft 14 is achieved, for example, by chrome plating or by plasma spraying with harder materials, for example, tungsten carbide or ceramic materials.
Although in a preferred embodiment of the invention as described above, a two-piece centralizer sleeve in which one piece has a locking tongue, and the other has a complementary locking groove is described, other complementary locking means can be used.
Further, centralizer sleeves can be composed of more than two pieces and need not be cylindrical. For example, a centralizer in the shape of a helically wound band (not shown) can also be used.
In addition, while the preferred embodiments above describe the use of a single centralizer sleeve on. each coupling, it will be readily understood that two or more centralizer sleeves can be used.
_g_ While only specific embodiments of the invention have been described, it is apparent that additions and modifications can be made thereto, and various alternatives can be selected. It is, therefore, the intention in the appended claims to cover all such additions, modifications and alternatives as may fall within the true scope of the invention.
The outside diameter of the shaft 14 is less than the outside diameter of the box ends 12. It can be even less than the diameter of the internally threaded bore 16 in which case the solid, unthreaded portion of the box ends 12 is extended in axial direction to provide added strength at the juncture of the shaft with the box ends. It is over this shaft 14, and between the end shoulders 15 of the box ends that the centralizer sleeve is positioned. The reduced diameter of the shaft 14 allows the use of a centralizer sleeve 11 of greater shell thickness which in turn translates into greater centralizer sleeve strength.
The exploded view of Figure 3 illustrates how the centralizer sleeve 11 fits over the box ends 12 in the preferred embodiment of the invention. In the embodiment illustrated, the centralizer sleeve 11 is split along an axial plane into a pair of sleeve portions 17 and 18, which in this embodiment are made of a hard wearing material such as Kevlar°. The sleeve portions are provided with interlocking structures for connecting them. Preferably, the first sleeve portion 17 has a locking tongue 19 running the length of each of the lateral edges of the first portion 17. This locking tongue 19 is complementary in shape to a longitudinal locking groove 20 which runs the length of each of the lateral edges of the second portion 18. In operation, the first and second centralizer sleeve portions 17, 18 are interlocked by the complementary tongues 19 and grooves 20 to form a cylindrical centralizer sleeve 11 that fits over the shaft 14. The inner diameter of the centralizer sleeve 11 is less than the outer diameter of the coupling ends 12 to prevent the centralizer sleeve sliding off the shaft 14 over one of the coupling ends. The sleeve 11 preferably slidably closely fits over the shaft 14 to prevent wobble of the sleeve relative to the shaft during rotation of the sucker rod string. The outer diameter of the centralizer sleeve 11 is larger than the outer diameter of the box ends 12 to prevent contact thereof with the production tubing which would result in wear of the box ends and the tubing.
In the preferred embodiment, the centralizer sleeve 11 consists of a tubular body 21 which in the assembled condition continuously surrounds the shaft 14. The wall thickness of the tubular body 21 is a principle determinant of the strength of the sleeve 11.
Integral to the centralizer sleeve 11, and on the outer surface thereof, are a series of spaced apart spacer fins 22 which maintain the necessary spacing between the centralizer sleeve and the production tubing to permit passage of the well fluid being pumped.
The height of the spacer fins 22 is substantially equal to the distance between the surface of the body 21 and the inner diameter of the production tubing. Thus, the height of the spacer fins 22 is determined by the diameter of the tubing, the diameter of the sleeve, and the desired volume of the annular space between the sleeve body and the tubing.
The spacer fins 22 in the illustrated embodiment are straight and extend parallel to the axis of the sleeve 11. However, for applications of the centralizer with reciprocating strings, they may also be positioned at an angle to the axis or may be curved.
The centralizer sleeve remains stationary and the sucker rod string rotates inside of it. Therefore, the centralizer assembly operates as a bearing. Curved spacer fins provide slightly better stand-off, but the advantage is slight and the disadvantage is a higher pressure drop.
The extension of the spacer fins 22 above the outer diameter of the box ends 12 is more clearly illustrated in Figure 4. The spacer fins 22 are preferably of trapezoid cross-section to reduce wear on the production tube but can be of rectangular, square or rounded cross-section.
_g_ In another preferred embodiment, the centralizer sleeve 11 consists of a single part. As illustrated in Figure 5, the single-piece centralizer sleeve 11 includes a slit 24 which runs the length of the centralizer sleeve 11 and allows the sleeve 11 to be forced open for sliding over the shaft 14 or one of the box ends 12 for installation onto the shaft. The slit is preferably placed at an angle to the axis of the sleeve to provide the sleeve with greater flexibility, but can be positioned parallel thereto or of helical shape. The sleeve 11 is preferably made of a flexible plastic material, such as Nylon°. Materials which are flexible and have good abrasion resistance may also be advantageously used, for example Teflon~. In both of the above embodiments the centralizer sleeve 11 can be replaced while the centralizer coupling 10 is incorporated in a sucker rod string (not illustrated).
In order to reduce wear of the stop shoulders 15, the shaft 14 and the centralizer sleeve 11, the wear surfaces of the stop shoulders 15 and the shaft 14 are chrome plated. The preferred materials used for the centralizer sleeves are usually resistant to abrasion and therefore it is generally the shaft 14 which is subjected to the most wear if not protected by a hard surface. Thus the shaft 14 is preferably provided with a hardened or hard coated surface. A hard facing of the shaft 14 is achieved, for example, by chrome plating or by plasma spraying with harder materials, for example, tungsten carbide or ceramic materials.
Although in a preferred embodiment of the invention as described above, a two-piece centralizer sleeve in which one piece has a locking tongue, and the other has a complementary locking groove is described, other complementary locking means can be used.
Further, centralizer sleeves can be composed of more than two pieces and need not be cylindrical. For example, a centralizer in the shape of a helically wound band (not shown) can also be used.
In addition, while the preferred embodiments above describe the use of a single centralizer sleeve on. each coupling, it will be readily understood that two or more centralizer sleeves can be used.
_g_ While only specific embodiments of the invention have been described, it is apparent that additions and modifications can be made thereto, and various alternatives can be selected. It is, therefore, the intention in the appended claims to cover all such additions, modifications and alternatives as may fall within the true scope of the invention.
Claims (10)
1. A sucker rod centralizer coupling, for use in a tubing comprising:
(a) a pair of box ends, each having an axial internally threaded bore for attachment to a pin end of a sucker rod;
(b) an intermediate shaft integral with and extending between said box ends, an outer diameter of the shaft being less than an outer diameter of the box ends;
and (c) a centralizer sleeve for slidably and rotatably fitting onto the shaft, the sleeve having a body and means for spacing the body from the tubing to allow passage of well fluids pumped through the tubing, an outer diameter of the centralizer sleeve being greater than the outer diameter of the box ends, the centralizer sleeve being divided into first and second sleeve portions for installation of the centralizer sleeve onto the shaft, the sleeve portions respectively including complementary connecting means for connecting the sleeve portions to one another to retain the sleeve about the shaft.
(a) a pair of box ends, each having an axial internally threaded bore for attachment to a pin end of a sucker rod;
(b) an intermediate shaft integral with and extending between said box ends, an outer diameter of the shaft being less than an outer diameter of the box ends;
and (c) a centralizer sleeve for slidably and rotatably fitting onto the shaft, the sleeve having a body and means for spacing the body from the tubing to allow passage of well fluids pumped through the tubing, an outer diameter of the centralizer sleeve being greater than the outer diameter of the box ends, the centralizer sleeve being divided into first and second sleeve portions for installation of the centralizer sleeve onto the shaft, the sleeve portions respectively including complementary connecting means for connecting the sleeve portions to one another to retain the sleeve about the shaft.
2. The centralizer coupling of claim 1, wherein a surface of the shaft is at least partly covered with a wear-resistant coating.
3. The centralizer coupling of claim 1 or 2, wherein at least one of the box ends has a wear-resistant coating on an end shoulder engaging the centralizer sleeve during use.
4. The centralizer coupling of claim 2 or 3, wherein the wear-resistant coating is chrome plating.
5. The centralizer coupling of claim 2 or 3, in which the wear-resistant coating is applied by plasma spraying of a hard metal coating.
6. The centralizer coupling of claim 5, in which the wear-resistant coating is provided by plasma spraying with tungsten carbide.
7. The centralizer coupling of any one of claims 1 to 6, in which the centralizer sleeve portions are made of Kevlar®.
8. The centralizer coupling of any one of claims 1 to 6, in which the centralizer sleeve portions are made of a Kevlar® blend.
9. The centralizer coupling of one of claims 1 to 8, in which an outside diameter of the shaft is smaller than an inside diameter of the internally threaded bore of the box ends.
10. The centralizer coupling of claims 1 to 9 in which the outer diameter of the centralizer sleeve is selected for the centralizer to tightly fit into the production tubing to prevent rotation of the sleeve relative to the production tubing.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US36970499A | 1999-08-06 | 1999-08-06 | |
| US09/369,704 | 1999-08-06 |
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| Publication Number | Publication Date |
|---|---|
| CA2315730A1 CA2315730A1 (en) | 2001-02-06 |
| CA2315730C true CA2315730C (en) | 2006-10-31 |
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| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA 2315730 Expired - Lifetime CA2315730C (en) | 1999-08-06 | 2000-08-04 | Centralizer for sucker rod strings |
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| CA (1) | CA2315730C (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
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| DE102010025491A1 (en) | 2010-06-29 | 2011-12-29 | Netzsch-Mohnopumpen Gmbh | Retention device for preventing sedimentation in boreholes |
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN102031933B (en) * | 2009-09-24 | 2013-03-13 | 江苏宏泰石化机械有限公司 | Serial anti-fall centralizer |
| CN103334705A (en) * | 2013-08-01 | 2013-10-02 | 南通奥里斯特机械有限公司 | Novel sucker rod centering device |
| CN107130923A (en) * | 2017-06-22 | 2017-09-05 | 泰州市时代科研设备仪器有限公司 | A kind of abrasion-resistant alloy protective pipe connector of oil-pumping rod with guide function |
| CN107130922A (en) * | 2017-06-22 | 2017-09-05 | 泰州市时代科研设备仪器有限公司 | Multifunctional pumping rod abrasion-resistant alloy protective pipe connector |
| CN108843256B (en) * | 2018-08-14 | 2024-10-15 | 河南福侨石油装备有限公司 | Sucker rod fixed centralizer and preparation method thereof |
| DE102020200664A1 (en) * | 2020-01-21 | 2021-07-22 | MTU Aero Engines AG | Method for repairing a sealing air device for a turbo machine, sealing air device and turbo machine with a sealing air device |
| CN111287676B (en) * | 2020-04-15 | 2024-11-22 | 江苏赛瑞机器人装备有限公司 | A roller type automatic opening and closing oil pipe centralizer |
| CN114718509B (en) * | 2021-01-05 | 2023-11-28 | 中国石油天然气股份有限公司 | Wax-proof and scale-proof device for oil well |
| CN113982502B (en) * | 2021-09-29 | 2024-03-29 | 天津市金升石油机械设备有限公司 | Screw pump wear-proof device and manufacturing method thereof |
-
2000
- 2000-08-04 CA CA 2315730 patent/CA2315730C/en not_active Expired - Lifetime
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| DE102010025491A1 (en) | 2010-06-29 | 2011-12-29 | Netzsch-Mohnopumpen Gmbh | Retention device for preventing sedimentation in boreholes |
Also Published As
| Publication number | Publication date |
|---|---|
| CA2315730A1 (en) | 2001-02-06 |
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