Patent Application
20220205331
In the resource recovery industry it is common to run an inflow test packer to test for leakage at an intersection of a parent casing and depending liner. Traditionally, the inflow test packer is set with set down weight borne by an upholemost portion “liner top” of a liner top assembly. A “liner top assembly” as used herein may be a liner hanger/anchor and/or a liner top packer since any combination of these may be used at the uppermost end of a liner in a casing from which the liner depends in various well constructions. Accordingly, it should be understood that when a “liner top” is referred to herein, it can mean an upholemost end of the liner itself, the upholemost end of the liner hanger/anchor, or the upholemost end of the liner top packer. The terms are used in this way to ensure understanding that “liner top” is the uppermost portion of whatever construction is connecting the liner back to the parent casing and is something against which a load may be set down. Setting down weight of the string of which the inflow test packer is a part onto the liner top has been a successful method for setting the inflow test packer and is widely used. However, in situations where other tools such as wellbore clean up tools are run below (downhole of) the inflow test packer at the same time, a long string of heavy wall drill pipes necessarily must be installed between the packer and the other tools to space them out so that while the inflow test packer is close the liner top, the clean-up tools reach the total depth of the well, for example. The additional tools and drill pipe significantly increase the weight of the string. In accordance with teaching in the art prior to the present disclosure, in order to activate the inflow test packer, all the weight hanging below the packer has to be borne on the line top. With this issue having been recognized and herein disclosed by the present inventors, it becomes evident that the load on the liner top is quite high necessitating a more robust liner hanger with a higher hanging capacity than otherwise necessary. Robustness increases expense for manufacturers and is therefore undesirable. The art always is receptive to new tools and methods that reduce cost while maintaining functionality.
An embodiment of a an inflow test packer tool including a packer configured for fixed attachment to a string, a liner top mating member operably connected to the packer by a setting extension, the setting extension configured for setting the packer upon set down weight against a liner top through the liner top mating member, and a mandrel fixedly attached relative to the packer and extending through the liner top mating member to provide a weight bearing connection independent of the liner top mating member for additional downhole tools depending downhole of the packer and the liner top mating member.
An embodiment of an inflow test packer tool including a packer, a liner top mating member operably connected to the packer, and a weight carrying configuration bypassing the packer and liner top mating member.
A method for setting an inflow test packer including disposing the packer, a liner top mating member and one or more additional tools downhole of the packer and liner top mating member on a string, running the string into a borehole having a liner therein, the liner including a liner top, engaging the liner top mating member with the liner top, setting down weight on the liner top associated with setting of the packer while supporting weight of the additional tools with the string, and maintaining the weight of the additional tools isolated from the liner top.
The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:
The FIGURE is a three-quarter section view of an inflow test packer tool as disclosed herein.
A detailed description of one or more embodiments of the disclosed apparatus and method are presented herein by way of exemplification and not limitation with reference to the FIGURE.
Referring to the FIGURE, an inflow test packer tool 10 as disclosed herein is illustrated. The tool 10 includes an inflow test packer 12, a liner top mating member 14, a setting extension 16, a pipe segment 18 and a mandrel 20. Attention is directed to mandrel 20 and its connections at either end thereof. The mandrel 20 is connected at a thread 22 to the pipe segment 18 and while not shown the additional downhole tools whose weight the mandrel is configured to carry are connectible at thread 24. It will be appreciated that a load connected to thread 24 will be transferred directly to thread 22 without regard for the packer 12 or the member 14. Pipe segment 18 is configured to be attached to a string 30 at thread 26 so that the load is carried all the way back to the rig (not shown). Packer 12 and member 14 are disposed upon the mandrel 20 in such way that the packer 12 is settable by set down weight upon the member 14. The packer 12 may be in a fixed position relative to the pipe segment 18 while the member 14 may be mobile relative to the packer 12. Specifically, the member 14 is configured to land upon a liner top (not shown but well known). Once landed, continued set down weight will cause the member 14 to move toward the packer 12. The extension 16 will at a predetermined amount of axial movement contact an actuating part of the packer 12 and begin to set the packer 12 by compression. It is noted that because of the mandrel 20, only the weight needed to set the packer 12 and any built in load requirement associated with a release mechanism such as shear screw 32 is transferred to the liner top. This is because any additional weight connected to the tool 10 is still being supported through the string 30. This is a significant benefit over the prior art which requires that the weight needed to set the packer 12 and any built in load requirement associated with a release mechanism plus additional weight connected to the tool be borne by the liner top. Requiring that the hanger have sufficient weight competence increases costs for the hanger. With the teachings herein, liner hangers may be constructed more economically.
In other respects, the tool 10 retains the utility of prior art units with regard to torque transfer through lug 34 which rotationally locks the mandrel 20 to a housing 36 of the mating member 14. In addition, functions such as liner dressing are available when the mating member 14 is a liner dress mill (rotationally drivable through the lug 34.
Set forth below are some embodiments of the foregoing disclosure:
Embodiment 1: An inflow test packer tool including a packer configured for fixed attachment to a string, a liner top mating member operably connected to the packer by a setting extension, the setting extension configured for setting the packer upon set down weight against a liner top through the liner top mating member, and a mandrel fixedly attached relative to the packer and extending through the liner top mating member to provide a weight bearing connection independent of the liner top mating member for additional downhole tools depending downhole of the packer and the liner top mating member.
Embodiment 2: The tool as in any prior embodiment, wherein the liner top mating member is a liner dress mill.
Embodiment 3: The tool as in any prior embodiment, wherein the setting extension is configured to transfer load from the liner top mating member to the packer.
Embodiment 4: The tool as in any prior embodiment, wherein the setting extension, in use, causes a compressive force on the packer thereby setting the packer.
Embodiment 5: The tool as in any prior embodiment, wherein the mandrel is a single piece.
Embodiment 6: The tool as in any prior embodiment, wherein the mandrel extends through the packer.
Embodiment 7: The tool as in any prior embodiment, wherein the mandrel is fixedly connected to a connector to a string.
Embodiment 8: The tool as in any prior embodiment, wherein the connector is a pipe segment.
Embodiment 9: The tool as in any prior embodiment, wherein the weight bearing connection of the mandrel is a thread.
Embodiment 10: An inflow test packer tool including a packer, a liner top mating member operably connected to the packer, and a weight carrying configuration bypassing the packer and liner top mating member.
Embodiment 11: The tool as in any prior embodiment, wherein the weight carrying configuration carries a load directly to a string to which the tool is connected during use.
Embodiment 12: A method for setting an inflow test packer including disposing the packer, a liner top mating member and one or more additional tools downhole of the packer and liner top mating member on a string, running the string into a borehole having a liner therein, the liner including a liner top, engaging the liner top mating member with the liner top, setting down weight on the liner top associated with setting of the packer while supporting weight of the additional tools with the string, and maintaining the weight of the additional tools isolated from the liner top.
Embodiment 13: The method as in any prior embodiment, wherein the setting the packer is compressing the packer.
The use of the terms “a” and “an” and “the” and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should be noted that the terms “first,” “second,” and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The terms “about”, “substantially” and “generally” are intended to include the degree of error associated with measurement of the particular quantity based upon the equipment available at the time of filing the application. For example, “about” and/or “substantially” and/or “generally” can include a range of ±8% or 5%, or 2% of a given value.
The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a wellbore, and/or equipment in the wellbore, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc.
While the invention has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the claims. Also, in the drawings and the description, there have been disclosed exemplary embodiments of the invention and, although specific terms may have been employed, they are unless otherwise stated used in a generic and descriptive sense only and not for purposes of limitation, the scope of the invention therefore not being so limited.
