Patent Application
20230323742
The present disclosure relates in general to means for protecting against abrasive wear of a tubular string running inside a larger tubular string, and relates in particular to means for protecting against abrasive wear to tubular strings used to install and remove frac plugs in vertical, horizontal, and deviated oil and gas wells.
During a typical “well frac” (i.e., fraccing operation) for an oil or gas well, a frac fluid carrying a proppant (typically sand or ceramic particles) is pumped under high pressure into the subsurface reservoir through perforations in the well casing, in order to fracture the formation and thus increase the flow of formation fluids (e.g., gas and/or crude oil) to the well. Frac plugs are commonly used to isolate individual zones of a well during “plug-and-perf” completion operations in vertical, deviated, and horizontal wells. The frac plugs are set using wireline, coil tubing, or threaded pipe. A one-way internal check valve is closed with a ball while the zone above the plug is fractured. The plug can be run into the well with the ball in place, or the ball can be dropped from surface after the plug has been positioned in the well. The check valve allows free flow of fluids from below the plug after fraccing.
There are many different types of frac plugs, and numerous companies that make them. Some frac plugs have hollow metal button slips that are designed to shatter during milling while they are being drilled out (or “milled out”), as discussed later herein. This feature reduces the metal content of the plugs to decrease mill-out time and debris size when plugs are being removed after completion of fraccing operations for the affected formation zone. One specific example of a frac plug is the “Boss Hog” frac plug manufactured by Downhole Technology, LLC, of Houston, Texas.
The number of frac plugs required for a given fraccing operation is determined by the number of “stage fracs” to be performed on the well. For example, in the Montney Formation of the Western Canadian Sedimentary Basin, there have been wells with as many as 132 stage fracs, and thus as many as 132 plugs for a single well, as each stage is fracced separately. The frac plugs have to be drilled out (or “milled out”) after completion of each stage frac, commonly by means of string of pipe (commonly 2″ or 2½″ nominal diameter) or coil tubing utilizing a mud motor fitted with a milling tool to drill out the plugs. As the pipe (or tubing) string moves through the well, with or without rotation, it will rub against the inner surfaces of the steel casing, causing abrasion and wear to the casing and to the pipe (or tubing) carrying the mud motor. This is particularly true for horizontal and deviated wells where the pipe or tubing string has to bend as it passes through the radiused section where the well profile transitions from vertical to horizontal (or to other non-vertical angular orientations).
It is known to incorporate short tubular components (or “subs”) having an “upset” end (i.e., with a larger outside diameter and radial wall thickness than other portions of the pipe) at intermittent locations in tubing strings so that the upset section will take the brunt of the abrasive wear resulting from sliding and/or rotating contact with an enclosing casing string, with the extra thickness of the upset section ensuring that abrasive wear will not reduce the wall thickness of any portion of the sub to less than the original thickness of the non-upset portion of the sub.
When the upset section has become excessively worn, it can be rebuilt by “hardbanding”, a process that will be familiar to persons skilled in the art, and which involves deposition of wear-wear-resistant hardbanding alloys, such as by means of MIG (metal inert gas) welding or other welding processes. Hardbanding thus provides one way to address or mitigate the problem of abrasive wear to pipe strings moving and rotating within larger tubular strings. However, it is very expensive, both in terms of initial cost of the subs and in terms of the cost of applying remedial hardbanding to worn subs.
The process of drilling out frac plugs in a horizontal well can take a number of days, and due to depth, torque is critical. With very deep drill-outs in a deviated well (e.g., drill-outs near the toe of the horizontal section of the well), the pipe string can get stuck inside the casing (especially in the radiused transition section of the well), and there have been many cases where the pipe has become stuck and was twisted off due to torsional shear induced by rotation applied to the pipe string while it was stuck in the casing. In such cases it will be necessary to fish the sheared-off pipe out of the well, and in the worst case the well may be lost and a new well may have to be drilled.
For the foregoing reasons, there is a need for methods and means for reducing abrasive wear of tubular strings used in frac plug drill-out operations, and also a need for methods and means for reducing torque-induced stresses in such tubular strings, and thus to reduce the risk of the tubular strings becoming stuck in the casing and even shearing off. The present disclosure is directed to these needs.
In general terms, the present disclosure teaches non-limiting embodiments of circumferential wear bands that can be formed on a steel pipe string, at selected intervals along the length of the pipe string, to protect components of the pipe string from abrasive wear caused by sliding and/or rotating contact with interior surfaces of a larger-diameter tubing string (such as a casing string) within which the pipe string may be moving and/or rotating. The wear bands may be formed on individual lengths (or “joints”) of pipe making up the pipe string, or they can be provided on smaller pipe “subs” incorporated into the pipe string (as discussed above).
The wear bands are preferably made from a non-metallic material suitable for direct application onto steel pipe, such as by injection moulding, and which preferably has relatively high inherent abrasion resistance properties (to maximize the service life of the wear bands before they need to be replaced) and a relatively low coefficient of friction (to promote both longitudinal and rotational sliding of the wear bands relative to inner surfaces of a surrounding casing string so as to minimize induced frictional resistance between the wear bands and the casing string, and thus to minimize torsional and other structural stresses induced in the tubing string by such longitudinal and/or rotational sliding). Non-limiting examples of materials that may be suitable for making or forming wear bands in accordance with the present disclosure include polyketone, HDPE (high-density polyethylene), PEX (cross-linked polyethylene), Fortron® (polyphenylene sulfide), fiberglass, Amodel® (polyphthalamide), Ryton® (polyphenylene sulfide), PE-RT (polyethlene of raised temperature), UHMW-PE (ultra-high molecular weight polyethylene).
Additional non-limiting examples of materials that may be suitable for making or forming wear bands in accordance with the present disclosure include polyester-based and polyether-based thermoplastic polyurethanes (alternatively referred to as thermal polyurethanes and TPUs), and glass-reinforced TPUs containing between about 5% and about 25% glass by weight). In particular but non-limiting embodiments, the wear bands may be made from:
In one embodiment, the wear band is a fixed wear band that is injection-moulded directly onto the exterior surface of the pipe joint or sub. The pipe or sub surfaces onto which the wear band is to be injection-moulded will typically be prepared by wire brushing or other suitable means for removing mill scale and other contaminants from the pipe or sub surface, and thereby to promote a strong bond between the wear band and the pipe surface. In addition, a suitable bonding agent may be applied to the prepared surface prior to the injection-moulding process, as may be desired or appropriate for the materials being used.
Optionally, an annular groove may be formed into the circumferential surface of the wear band to act as a visual wear indicator, to assist well operators in assessing how much reliable service life is remaining for the wear band before it needs to be replaced.
In another embodiment, the wear band is a rotatable wear band provided in the form of multiple mating cylindroid sections (for example, a pair of semi-cylindrical sections) disposed and connected together within an annular recess formed in a circumferential collar that has been injection-moulded onto the pipe or sub in the same general manner as described above with respect to fixed wear band embodiments. The wear band is thus freely rotatable relative to the collar and the pipe (or sub), and thus can rotate relative to the casing when in rotational contact therewith, thereby reducing resultant wear to the wear band itself, and reducing or eliminating the risk of excessive torque developing in the pipe string due to contact with interior surfaces of the casing.
When the rotatable wear band has become worn and needs to be replaced, it is a relatively simple matter to remove the worn multi-piece wear band and replace it with a new one. This ability to replace worn rotatable wear bands makes it possible to greatly and relatively inexpensively extend the service life of a pipe section or sub carrying a rotatable wear band, as compared to fixed wear bands, because the collars moulded onto the pipe or sub to retain the rotatable wear bands will not be subject to abrasive wear in normal service (provided that worn rotatable wear bands are replaced before the risk of contact between the collars and the casing develops).
Wear bands in accordance with the present disclosure will reduce torque and resultant torsional stresses in the pipe string, and will prevent or reduce wear on the pipe string from rubbing against the inside of the casing. The wear bands also will make it easier for the pipe string to slide and rotate within the casing, thus increasing the depth to which the pipe can be inserted into the casing without fear of the pipe becoming stuck in the casing and even being twisted off due to high torque induced in the pipe as a result of being stuck in the casing. As well, the improved ability of the pipe to slide and rotate within the casing string because of the wear bands will reduce the time required for frac plug drill-outs, which is a significant benefit in light of the fact that the cost of these operations can be as much as $20,000 per day or more.
In accordance with the foregoing, in one aspect the present disclosure teaches a wear band assembly comprising a tubular member, plus a generally cylindrical wear band disposed circumferentially around and bonded to a selected portion of the length of the tubular member.
In a second aspect, the present disclosure teaches a wear band assembly comprising a tubular member; a generally cylindrical collar coaxially disposed around, and bonded to, a selected portion of the length of the tubular member, with the collar having an annular wear band retention groove coaxial with the tubular member, and with the wear retention groove having a cylindrical circumferential surface; and a generally cylindrical wear band rotatably and coaxially disposed within the wear band retention groove so as to be coaxially rotatable around the cylindrical circumferential surface of the wear band retention groove.
Embodiments will now be described with reference to the accompanying Figures, in which numerical references denote like parts, and in which:
Fixed wear bands 110 and 110A are shown herein as having bevelled annular portions at each end, but this is by way of non-limiting example only. In variant embodiments, wear bands 110 and 110A could be of simple cylindrical form (i.e., with a uniform outer diameter) with square-cut ends, to provide just one non-limiting example.
Wear band sections 221 are provided with fastening means 225 for securely connecting wear band sections 221 to each other to form rotatable wear band 220.
Circumferential collar 210 and wear band sections 221 are shown herein as having bevelled annular portions at each end, but this is by way of non-limiting example only. In variant embodiments, collar 210 and wear band sections 221 could be of simple cylindrical form (or semi-cylindrical, in the case rotatable wear bands 220 made up of two wear band sections 221), with square-cut ends. What is important, for purposes of preventing unwanted abrasion and wear on collar 210, and thus maximizing the service life of collar 210, is for at least a portion of the outer cylindrical surface of rotatable wear band 220 to have an initial diameter greater than the largest outer diameter of collar 210, such that only rotatable wear band 220, and not collar 210, will come into contact with inner surfaces of the bore of the casing string in which a tubing string fitted with rotatable wear bands 220 is being used.
Wear band sections 221 of rotatable wear band 220 are illustrated herein without wear indicator grooves like annular groove 120 of fixed wear band 110A. Abrasive wear on wear band sections 221 typically will be readily detectable using collar 210 as a visual comparative reference point. Optionally, however, wear indicator grooves could also be provided in variant embodiments of wear band sections 221.
Wear bands 110 and 110A, circumferential collar 210, and wear band sections 221 of wear band assemblies 200 may be made using any functionally suitable materials, including materials noted in the “Summary” section herein, selected to suit the particular service conditions in which they will be used. Collar 210 and wear band sections 221 of a given wear band assembly 200 may use the same or different materials.
The dimensions of wear bands in accordance with embodiments disclosed herein will typically be a matter of design choice to suit the particular service conditions in which the wear bands will be used. Accordingly, wear bands in accordance with the present disclosure are not limited or restricted to any particular dimensional constraints, such as with respect to axial length or radial thicknesses.
It will be readily appreciated by persons skilled in the art that various modifications to embodiments in accordance with the present disclosure may be devised without departing from the present teachings, including modifications that may use structures or materials later conceived or developed. It is especially to be understood that the scope of the present disclosure should not be limited by or to any particular embodiments described, illustrated, and/or claimed herein, but should be given the broadest interpretation consistent with the disclosure as a whole. It is also to be understood that the substitution of a variant of a claimed element or feature, without any substantial resultant change in functionality, will not constitute a departure from the scope of the disclosure or claims.
In this patent document, any form of the word “comprise” is intended to be understood in a non-limiting sense, meaning that any element or feature following such word is included, but elements or features not specifically mentioned are not excluded. A reference to an element or feature by the indefinite article “a” does not exclude the possibility that more than one such element or feature is present, unless the context clearly requires that there be one and only one such element.
Relational and conformational terms such as (but not limited to) “vertical”, “horizontal”, “cylindrical”, “semi-cylindrical”, and “coaxial” are not intended to denote or require absolute mathematical or geometrical precision. Accordingly, such terms are to be understood as denoting or requiring substantial precision only (e.g., “substantially vertical” or “generally horizontal”) unless the context clearly requires otherwise. In particular, it is to be understood that any reference herein to an element as being “generally cylindrical” is intended to mean that the element in question may have inner and outer diameters that vary along the length of the element.
Any use of any form of any term describing an interaction or connection between elements or features is not meant to limit the interaction to direct interaction between the elements or features in question, but may also extend to indirect interaction between the elements such as through secondary or intermediary structure. Any use of any form of the term “typical” is to be interpreted in the sense of being representative of common usage or practice, and is not to be interpreted as implying essentiality or invariability.
| Number | Date | Country | |
|---|---|---|---|
| 62797934 | Jan 2019 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 17423866 | Jul 2021 | US |
| Child | 18204890 | US |
