FIELD

[0001] This invention relates to tools used in oil and gas weilbores. More specifically, the disclosure relates to expansion sealing elements used to prevent fluid flow through an annulus formed by a tubing within the well and th e wall of the wellbore or casing.

BACKGROUND

[0002] In drilling or reworking of oil wells, a great variety of downhoie tools are used.

Downhole tools such as packers, bridge plugs and frac plugs are often used to seal the armulus formed by a tubing within the well and the wall of the wellbore or casing. For example, but not by way of limitation, it is often desirable to seal tubing or other pipe in the casing of the well when it is desired to pump cement or other slurry down the tubing and force the cement or slurry around the annulus of the tubing or out into a formation.

[0003] The seal for the annulus is generally established by a deformable element such as rubber or an elastomer. A compressive force is generally applied to the deformable element, causing it to extrude radially outward. The element extends from the outer portion of the mandrel of the downhoie tool to the wellbore wall or casing and seals between those structures.

[0004] Problems are encountered in the use of do wnhoie tools because of variations in wellbore or casing diameter. Thus, when a downhoie tool must be lowered through a smaller casing and sealed in a larger casing below the smaller casing, a sealing element that fits through the smaller casing may be too small to adequately expand to seal the larger size casing. Additionally, a sealing element of adequate size to seal the larger casing may be too large to fit into the smaller casing.

[0005] Thus, while there are a number of sealing elements available, there is a need for further such apparatuses that can meet the needs of different well operations utilizing different casing sizes.

BRIEF DESCRIPTION OF THE DRAWINGS

[0006] The drawings are provided to illustrate certain aspects of the invention and should not be used to limit or define the invention.

[0007] FIG. 1 is a front view of a sealing element in accordance with one embodiment.

The sealing element is in the run-in or unset configuration.

[0008] FIG. 2 is a sectional view of the sealing element of FIG. 1.

[0009] FIG. 3 is a sectional view of the sealing element of FIG. 1 when it is being changed from the unset configuration to a set configuration.

[0010] FIG . 4 is a sectional view of the sealing element of FIG . 1 in the set configuration.

[0011] FIG. 5 is a sectional view of the sealing element in the set configuration. The sealing element is set in a smaller diameter casing than that shown for FIGS. 1-4

[0012] FIG. 6 is a partial sectional view of a downhole tool incorporating the sealing element of one embodiment. The downhole tool is shown in its run-in or unset position.

[0013] FIG. 7 is a partial sectional view of the downhole tool of FIG. 5 shown in its set position. DETAILED DESCRIPTION

[0014] Referring now to the drawings, wherein like reference numbers are used herein to designate like elements throughout the various views, various embodiments are illustrated and described. The figures are not necessarily drawn to scale, and in some instances the drawings have been exaggerated and/or simplified in places for illustrative purposes only. In the following description, the terms "upper," "upward," "lower," "below," "downhole" and the like, as used herein, shall mean: in relation to the bottom or furthest extent of the surrounding welibore even though the well or portions of it may be deviated or horizontal. The terms "inwardly" and "outwardly" are directions toward and away from, respectively, the geometric center of a referenced object. Where components of relatively well-known designs are employed, their structure and operation wil l not be described in detail. One of ordinary skill in the art will appreciate the many possible applications and variations of the present invention based on the following description.

[0015] Referring now to FIGS. 1 and 2, a sealing element 10 is illustrated in its first position or unset position. Sealing element 10 is shown as being within a wall 42, which can be a casing wall or welibore wall. Sealing element 10 comprises a first sealing member 12 and a second sealing member 14. Generally, each sealing member is made from a deformable element such as rubber or an elastomeric compound, but can be made of thermoplastic or other various soft deformable materials. First sealing member 12 and second sealing member 14 are each disposed about a mandrel 16 of a downhole tool. The sealing element 10 is set between a first packer shoe 18 and second packer shoe 20, or between two other barriers at least one of which is moveable so that compression or longitudinal pressure can be applied to the sealing element 10. First packer shoe 18 and second packer shoe 20 are also disposed about mandrel 16 [0Θ1 ] As can best be seen from FIG, 2, first sealing member 12 is a generally cylindrical sealing element having an outer surface 22, an inner surface 24, a first end 26 and a second end 28. First end 26 abuts first packer shoe 18. inner surface 24 has an inclined inner wall 30 at second end 28.

[0017] Second sealing member 14 has an outer surface 32, an inner surface 34, a first end

36 and a second end 38. Second sealing member 14 is at least partially wedged or truncated conical in shape so that outer surface 32 has an inclined outer wall 40. Inclmed outer wal l 40 is at first end 26 of second sealing member 14 and adjacent second end 28 of first sealing member 12 when sealing element 10 is in its unset position. Thus, first sealing member 12 is longitudinally separated f om second sealing member 14. By "longitudinally separated" it is meant that the sealing members are spaced longitudinally along mandrel 16 such that there is only a minor portion of overlap or no overlap of the sealing members, that is there is no overlap that creates any significant radial expansion and, preferably, no radial expansion of either sealing member. As shown in FIG, 2, inclined inner wall 30 and inclined outer wall 40 overlap when sealing element 10 is in its unset position; however, as will be noted, neither first sealing member 12 nor second sealing member 14 have any radial expansion due to the overlap. Additionally, second end 38 of second sealing member 14 can be wedged or truncated conical in shape, as shown, or can be another suitable shape such as cylindrical.

[0018] As will be appreciated from FIG. 2, inner surface 24 and inner surface 34 are in contact with mandrel 16 when sealing element 10 is in its unset position. Also, outer surface 22 and outer surface 32 are exposed to but spaced away from the wall 42 of the wellbore, which may be a casing wall if the wellbore is lined. Accordingly, neither outer surface 22 nor outer surface 32 are in contact with wall 42. [0Θ19] Turning now to FIGS. 3 and 4, sealing element 10 is illustrated in transition from its unset position to its second or set position (FIG. 3) and is illustrated in its set position (FIG. 4). As will be appreciated from the drawings, as packer shoes 1 8 and 20 exert compression pressure on first end 26 of first sealing member 12 and second end 38 of second sealing member 14, the sealing members 12 and 14 move in relation to each other. During this relative movement, inclined inner wall 30 slides over inclined outer wall 40 causing first sealing member 12 to stretch over second sealing member 14 and come into sealing engagement with wall 42. Thus, during the transition from the unset position to the set position, first sealing member 12 moves from being longitudinally spaced from second sealing member 14 to being radially outward from the second sealing member such that outer surface 22 is in sealing engagement with wall 42. Also, when sealing element 10 is in its set position, inner surface 24 of first sealing member 12 is in sealing engagement with outer surface 32 of second sealing member 14, and inner surface 34 of second sealing member 14 is in sealing engagement with mandrel 16.

[0020] Sealing element 10 represents a more versatile sealing element than prior conventional sealing elements. Although designed for a specific casing diameter ("design size") such as that shown in FIGS. 1-4, sealing element 10 advantageously can also be utilized in smaller diameter casings. As shown in FIG. 5, when sealing element 10 is used in smaller diameter casing it achieves sealing without the complete overlap of sealing member 12 and sealing member 14. Thus, the amount that first sealing member 12 stretches over second sealing member 14 will be determined by the casing size. As illustrated in FIG. 5, when used in a casing having a diameter below the design size, first sealing member 12 stretches over second sealing member 14 so that only a first portion 44 of first sealing member 12 is radially outward from second sealing member 14 with the remaining portion or second portion 46 of first sealing member 12 being longitudinally spaced from second sealing member 14. In this position, outer surface 22 of at least the first portion 44 of first sealing member 14 is in sealing engagement with wall 42 and, depending on the size of the casing, a majority or even all of outer surface 22 can be in sealing engagement with wall 42. Additionally, the inner surface 24 of a second portion 46 of first sealing member 12 is in sealing engagement with mandrel 16 and inner surface 24 of first portion 44 is in sealing engagement with outer surface 32 of second sealing member 14. Inner surface 34 of second sealing member 14 is in sealing engagement with mandrel 16.

[0021] Turning now to FIGS. 6 and 7, the use of an embodiment of the sealing element

10 in a downhole tool 100 is shown. While the embodiment of FIGS. 5 and 6 illustrate downhole tool 100 as a packer tool, it should be understood that the invention is not limited to use in packer-type tools but is useful for any downhole tool for use in a wellbore requiring a fluid tight seal and is especially useful where there is a change in wellbore diameter such that the tool and expansion device must pass through a wellbore of smaller radius before being received into the wellbore where it will be placed in the set position. The latter wellbore having a greater radius than the wellbore of smaller radius.

[0022] Accordingly, in FIGS. 6 and 7, downhole tool 100 is shown in well comprising first wellbore or first casing 102 having a diameter Dl and a second wellbore or second casing 104 having a diameter D2. As can bee seen, Dl is less than D2. Downhole tool 100 can be lowered into a well on tubing or can be lowered on a wire line or other means known in the art (not shown). FIG. 5 shows the downhole tool 100 in its unset position and FIG. 6 shows downhole tool 100 in its set position.

[0023] Downhole tool 100 comprises a mandrel 106 with an outer surface 108 and inner surface 110. Mandrel 106 will typically be a dri liable material such as a polymeric composite. Mandrel 106 has a bore 112 defined by inner surface 110. Mandrel 106 has upper or top end 116 and lower or bottom end 1 18. Bore 1 12 defines a central flow passage therethrough. An end section 120 may comprise a mule shoe 120. Mule shoe 120 is shown as integrally formed with the mandrel 106 but can be a separate piece that is connected with pins to mandrel 106. Mule shoe 120 defines an upward facing shoulder 122 thereon.

[0024] Mandrel 106 has first or upper outer diameter 130, a second or first- intermediate outer diameter 132, which is a threaded outer diameter 132, a third or second-intermediate outer diameter 134 and a fourth or lower outer diameter 136. Shoulder 122 is defined by and extends between third and fourth outer diameters 134 and 136, respectively. Threads 138 are defined on threaded outer diameter 132. A. head or head portion 140 is threadedly connected to mandrel 112 and, thus, has mating buttress threads 142 thereon.

[0025] Head portion 140 has an upper end 144 that may comprise a plug or ball seat 146.

Head 140 has lower end 148 and has first, second and third inner diameters 150, 152 and 154, respectively. Buttress threads 142 are defined on third inner diameter 154. Second inner diameter 152 has a magnitude greater than first inner diameter 150 and third inner diameter 154 has a magnitude greater than second inner diameter 152. A shoulder 156 is defined by and extends between first and second inner diameters 150 and 152. Shoulder 156 and upper end 120 of mandrel 106 define an annular space 158 therebetween. In the embodiment illustrated, a spacer sleeve 160 is disposed in annular space 158. Spacer sleeve 160 has an open bore 162 so that fluid may pass unobstructed therethrough into and through longitudinal central flow passage 124. Head portion 140 may be disconnected by unthreading from mandrel 106 so that instead of spacer sleeve 160, a plug may be utilized. The plug will prevent flow in either direction and, as such, the tool will act as a bridge plug. [0Θ26] A spacer ring 164 is disposed about mandrel 106 and abuts lower end 148 of head portion 140 so that it is axiallv restrained on mandrel 106. Downhoie tool 100 further comprises a set of expansion apparatuses 166 as described in co-pending US Patent Application Serial Number 14/848,323, filed January 31, 2013, the disclosure of which is hereby incorporated by reference. Expansion apparatuses 166 comprise first and second or upper and lower expansion apparatuses 167 and 168. Upper and lower expansion apparatuses 167 and 168 are generally identical in configuration but their orientation is reversed on mandrel 106. Expansion apparatuses 167 and 168 have slip rings 170. Slip rings 170 are segmented slip rings and are shown as having buttons 172 secured to the outer surface thereof. When downhoie tool 100 is moved to the set position, as shown in FIG. 6, buttons 172 will gripping! y engage second casing 104 to secure downhoie tool 100 in the we!ibore. Buttons 172 comprise a material of sufficient hardness to partially penetrate second casing 104 and may be comprised of metallic-ceramic composite or other material of sufficient strength. Expansion apparatuses 167 and 168 further have expansion wedges 174, which are segmented wedges. Expansion wedges 174 are likewise disposed about mandrel 106. Further, expansion apparatuses 167 and 168 have wedges 176, which are disposed about mandrel 106. Wedges 176 are in contact with expansion wedges 174.

[0Θ27] Sealing element 10, which is an expandable sealing element, as described above, is disposed about mandrel 106 and has first and second sealing members 12 and 14. The embodiment illustrates a single sealing element; however, a multiple piece packer configuration can be used. First and second sealing members 12 and 14 abut the ends of wedges 176 of upper and lower expansion apparatuses 167 and 168, respectively.

[0028] In operation, the downhoie tool 100 in FIG. 6, in run-in configuration or unset position, is lowered into (run-in) the well by means of a work string of tubing sections or coupled tubing attached to the upper end 144 of head portion 140, A setting tool can be part of the work string. The downhole tool 100, in its unset position, fits through first casing 102, which has the smaller diameter of the two casings 102 and 104. Downhole tool 100 is then positioned in second casing 104. When downhole tool 100 is at a desired depth in the well, the setting tool is actuated and it drives spacer ring 164 from its run-in configuration to the set position shown in FIG, 7, Spacer ring 164 as well as other components, such as wedge 176 of upper expansion apparatus 167, can be held in place during run-in by shear pins. The axial pressure provided by the setting tool is sufficient to shear the shear pins to allow the components held by the shear pins to move to their set position.

[0029] As the distance between spacer ring 164 and the mule shoe 120 is decreased, each expansion apparatus 166 is longitudinally compressed, as is sealing element 10. With sufficient compression and sufficient resultant relative movement among the components of the expansion apparatuses 166 (wedges 176, expansion wedges 174 and slip rings 170) the connections between the wedge segments of expansion wedge 174 are sheared and the connections between the slip segments of slip ring 170 are sheared thus separating the wedge segments from each other and the slip segments from each other.

[0Θ30] With subsequent relative movement among wedge 176, expansion wedge 174 and slip ring 170, wedge 176 is slid under wedge segments of expansion wedge 174 driving them radially outward to their expanded configuration. Similarly, the wedge segments of expansion wedge 174 is slid under the slip segments of slip ring 170 driving them radially outward to their expanded configuration so that buttons 172, or other suitable gripping elements, grippingly engage second casing 104, During the reduction in distance between spacer ring 164 and mule shoe 120, first sealing member 12 and second sealing member 14 are compressed such that first sealing member 12 is stretched over second sealing member 14 and first sealing member 12 seals against the second casing 104. FIG, 7 shows the downhole tool 100 in its set position with expansion apparatuses 166 in its expanded configuration and with sealing element 10 sealed against casing 104.

[0031] In accordance with the above description a few exemplar}' embodiments will now be described. In a first embodiment there is provided a sealing element for a downhole tool, comprising a first sealing member and a second sealing member. The first sealing member engages the second sealing member such that the sealing element has a first position and a second position. In the second position, the first sealing member stretches over the second sealing member. In one aspect of this embodiment, the first sealing member can be radially outward from the second sealing member when the sealing element is in the second position. In another aspect, the sealing element moves from the first position to the second position under compression or tension. Also, the first sealing member can have an inner surface with an inclined inner wall and the second sealing member can have an outer surface with inclined outer wall. The inclined inner wall matches the inclined outer wall so as to facilitate the stretching of the first sealing member.

[0Θ32] In a further aspect of this embodiment, when the sealing element is in the second position, the outer surface of the first sealing member is in sealing engagement with a wall of a wellbore; the inner surface of the first sealing member is in sealing engagement with the outer surface of the second sealing member; and the inner surface of the second member is in sealing engagement with a mandrel of the downhole tool.

[0033] In another embodiment, there is provided a downhole tool for use in a wellbore comprising a mandrel, a first sealing member and a second sealing member. The first sealing member is disposed about the mandrel. The second sealing member is disposed about the mandrel. When the downhole tool moves from an unset position to a set position, the first sealing member moves in relation to the second sealing member such that the first sealing member sealingly engages the wellbore. Further, when the downhole tool moves from an unset position to a set position, the first sealing member sealingly engages the second sealing member and the second sealing member sealingly engages the mandrel.

[0034] In a further aspect of this embodiment, the first sealing member is longitudinally separated from the second sealing member when the downhole tool is in the unset position, and the first sealing member is radially outward from the second sealing member when the downhole tool is in the second position.

[0035] In still a further aspect, the first sealing member stretches over the second sealing member when the downhole tool moves from the unset position to the set position. Also, the first sealing member can have an inner surface with an inclined inner wall and the second sealing member can have an outer surface with inclined outer wall. The inclined inner wall matches the inclined outer wall so as to facilitate the stretching of the first sealing member. Additionally, when the downhole tool moves from the unset position to the set position, compressive forces can be applied to the first sealing member and to the second sealing member thus moving the first sealing member from being longitudinally separated from the second sealing member to being radially outward from the second sealing member.

[0036] in another embodiment, there is provided a method of operating a servicing tool in a wellbore comprising:

longitudinally compressing a sealing element along a central axis, wherein the sealing element has a first sealing member and a second sealing member and the compressing results in relative axial movement of the first sealing member and the second sealing member;

upon sufficient compression, expanding the first sealing member such that it stretches over the second sealing member and seaiingly engages the wellbore.

[0Θ37] In a further aspect of this embodiment, during the relative axial movement, the first sealing member moves from being longitudinally separated from the second sealing member to being radially outward from the second sealing member. Also, after the first sealing member stretches over the second sealing member, the first sealing member seaiingly engages the second sealing member. In another aspect of this method, the first sealing member has an inner surface with an mclined inner wall and the second sealing member has an outer surface with an inclined outer wall. The inclined inner wall matches the inclined outer wall so that the first sealing member stretches over the second sealing member by the inclined inner wall moving along the inclined outer wail.

[0038] Other embodiments will be apparent to those skilled in the art from a consideration of this specification or practice of the embodiments disclosed herein. Thus, the foregoing specification is considered merely exemplary with the true scope thereof being defined by the following claims.