Patent Application
20230407712
In the resource recovery and fluid sequestration industry, various types of drill strings are deployed in a borehole for purposes such as exploration and production of hydrocarbons. A drill string generally includes drill pipe or other tubular and a bottomhole assembly (BHA). While deployed in the borehole, the drill string may be subject to a variety of forces or loads. For example, the BHA or other components can experience torsional vibrations having various frequencies and simultaneously rotating bending loads. Such vibrations, including high-frequency vibrations and loads, can cause irregular downhole rotation, reduce component life and compromise measurement accuracy.
An embodiment of a coupling device includes an elongated coupler body configured to be deployed at a borehole string and connected to a downhole component of a borehole string. The coupler body has a longitudinal axis, and the coupler body has a torsional stiffness sufficient to transmit rotational motion to the connected downhole component. The coupling device also includes at least one recess formed in a wall of the coupler body, the at least one recess extending along a periphery of the coupler body in a direction generally perpendicular to the longitudinal axis. The at least one recess is configured to impart a bending stiffness that is less than or equal to a reference bending stiffness, and the torsional stiffness and the bending stiffness are selected to modify a mode shape of an undesired torsional oscillation.
An embodiment of a method of performing a subterranean operation includes deploying a borehole string in a borehole, performing the subterranean operation, the performing including rotating a downhole component, and modifying undesired oscillations occurring due to the rotating by a coupling device connected to the downhole component. The coupling device includes an elongated coupler body having a longitudinal axis and a torsional stiffness sufficient to transmit rotational motion to the downhole component, and at least one recess formed in a wall of the coupler body. The at least one recess extends along a periphery of the coupler body in a direction generally perpendicular to the longitudinal axis, and the at least one recess imparts a bending stiffness that is less than or equal to a reference bending stiffness, the torsional stiffness and the bending stiffness selected to modify a mode shape of an undesired torsional oscillation.
The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:
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 Figures.
Apparatuses and methods for performing subterranean operations and damping undesired vibrations or oscillations are described herein. Embodiments include a torsionally stiff and laterally flexible coupling device (also referred to as a “coupler”) that is configured to be disposed with a borehole string, such as a drill string and/or logging-while-drilling (LWD) string. The coupler is configured to aid in damping or reducing undesired torsional vibrations or oscillations, such as stick/slip oscillations and high frequency torsional oscillations. The coupler aids or facilitates the effectiveness of a damping device by modifying or tuning mode shapes of undesirable torsional oscillations so that the damping device can more effectively damp such oscillations.
The coupler is “torsionally stiff” in that the coupler is capable of effectively transmitting rotational motion in the drill string. The coupler, by virtue of at least the torsional stiffness, is configured to favorably tune vibrational mode shapes (e.g., by shifting location of maxima and minima, changing amplitude, changing frequency and/or modifying other parameters of a vibrational mode). The coupler can thus improve the utilization of damping devices.
The coupler body or structure may include one or more bending features that allow the coupler to maintain torsional stiffness while being laterally flexible. “Lateral flexibility” or “bending flexibility” refers to a property of the coupler that allows the coupler to bend in a lateral direction that is generally perpendicular to a longitudinal axis of the coupler, borehole string and/or borehole. The bending features, in an embodiment, impart bending flexibility such that the bending stiffness is below a selected stiffness threshold and/or a ratio of bending stiffness to torsional stiffness is below a threshold ratio value.
An embodiment of the coupler includes one or more recesses in the coupler body that impart a desired bending stiffness. The recesses extend along a periphery or circumference of an outer surface of the coupler body in a direction that is perpendicular or generally perpendicular to a longitudinal axis of the coupler body. “Perpendicular” refers to an angle of 90 degrees between the longitudinal axis of the coupler body and the direction of the extension of the recess along the circumference of the coupler. “Generally perpendicular” refers to the direction of the extension of the recess along the circumference of the coupler forming an angle to the longitudinal axis of greater than or equal to 80 degrees, or greater than or equal to 85 degrees. In an embodiment, the direction of the extension of the recess along the circumference of the coupler may form an angle with the longitudinal axis that slightly deviates from 90 degrees, such as a deviation within 0.1 to 4.9 degrees, a deviation within 0.1 to 10 degrees, or a deviation within 0.1 to 15 degrees. The recesses may be at least partially filled with a flexible material, such as rubber or an elastomer. In an embodiment, the coupler includes one or more slots that extend circumferentially along a periphery of the coupler body in the generally perpendicular direction. The slots or recesses may include various stress relief features that allow the coupler to bend without damaging or overly stressing the coupler body.
Embodiments described herein provide a number of advantages and technical effects. The coupling devices and systems described herein provide an effective mechanism to support damping devices and elements in compensating for unwanted oscillations by providing coupling devices that have torsional stiffness and bending flexibility. Such coupling devices are able to effectively transmit rotational motion while aiding in damping undesirable modes (e.g., stick/slip and high frequency oscillations). In addition, the coupling devices described herein require fewer components and have fewer moving parts as compared to other damping devices.
The coupling devices described herein are advantageous over conventional torsional flex couplings (flex subs), which are typically made of a single piece of material but are flexible due to a smaller outer diameter in the flex area. This smaller diameter, which increases flexibility, also decreases the torsional stiffness significantly and in this way, decouples the damping device in a BHA from torsional oscillations. Decoupling torsional oscillations from the damping device makes the damping device become ineffective or work inefficiently. The coupling devices described herein provide flexibility while retaining torsional stiffness. The torsional stiffness allows transfer of torsional oscillations through a coupler to a damping device so that damping of the torsional oscillation at the damping device is performed effectively. The coupling device at the same time is bending flexible, supporting high build rates (angle from vertical direction per drilled distance) of the BHA and thus good directional drilling properties of the BHA.
The borehole string 12 is operably connected to a surface structure or surface equipment 18 such as a drill rig, which includes or is connected to various surface components. In an embodiment, the borehole string 12 is a drill string including one or more drill pipe sections that extend downward into the borehole 14, and is connected to various downhole components, all or some of which may be incorporated in a bottomhole assembly (BHA) 20.
The BHA 20 includes a drill bit 22, which may be driven from the surface (e.g., via a surface drive or rotary table, or driven by a downhole mud motor 24. The surface equipment 18 includes components to facilitate circulating fluid such as drilling mud through an inner bore of the borehole string 12 and an annulus between the borehole string 12 and the borehole wall. For example, a pumping device 26 is located at the surface to circulate the fluid from a mud pit or other fluid source 28 into the borehole 14 as the drill bit 22 is rotated. The borehole string 12 is discussed as a drill string 12, but is not so limited and can be any type of borehole string (e.g., string for hydraulic fracturing and/or other stimulation, wireline string, wellbore intervention string, fishing string, milling string, etc.)
The system 10 may include one or more of various downhole components configured to perform selected functions downhole such as controlling drilling, controlling drilling direction, performing downhole measurements, facilitating communications, performing stimulation operations and/or performing production operations. For example, the downhole components include a logging while drilling (LWD) or measurement while drilling (MWD) tool 30, the mud motor, a rotary steerable component (e.g., a rib-based or other steering head) and a stabilizer 32 or vibration damping devices.
Other components may include a telemetry assembly such as a mud pulse telemetry (MPT) assembly, for communicating with the surface and/or other downhole tools or devices. The telemetry assembly includes, for example, a pulser that generates pressure signals through the fluid.
The system 10, in an embodiment, includes a damping device 34 configured to provide torsional vibration damping and mitigate vibrations such as stick/slip and HTFO vibrations. The number, type and location of damping devices 34 is not limited to that shown in
Examples of a hydraulic damping device are discussed in US Patent Publication No. 2021/0079976 A1, assigned to Baker Hughes Oilfield Operations LLC, and entitled “Viscous Vibration Damping of Torsional Oscillations”, which is incorporated by reference herein in its entirety.
Additional examples of friction type dampers and hydraulic dampers, and methods of locating damping devices, are further discussed in US Patent Publication No. 2021/0079738 A1, assigned to Baker Hughes Oilfield Operations LLC, and entitled “Optimized Placement of Vibration Damper Tools Through Mode-Shape Tuning”, which is incorporated by reference herein in its entirety.
One or more downhole components and/or one or more surface components may be in communication with and/or controlled by a processor such as a downhole processor and/or a surface processing unit 38. The surface processing unit 38 may control various parameters such as rotary speed, weight-on-bit, fluid flow parameters (e.g., pressure and flow rate) and others. The surface processing unit 38, in one embodiment, includes an input/output (I/O) device 40, a processor 42, and a data storage device 44 (e.g., memory, computer-readable media, etc.).
The system 10 includes at least one coupling or connection device configured to connect components of the drill string 12. The device, referred to herein as a coupler 50, is configured to support damping of torsional vibrations, such as high frequency torsional oscillations (HFTOs). The coupler 50 has a high torsional stiffness and low bending stiffness (high bending flexibility), which has been found to be effective in combination with a damping device configured to damp bit-induced and other high frequency torsional vibrations. The coupler 50 includes one or more bending features designed to provide flexibility in the lateral direction and allow the torsionally stiff coupler 50 to bend.
In an embodiment, the coupler 50 includes a coupler body 52 and one or more circumferentially extending recesses 54 that allow for a selected amount of bending. The selected amount of bending, along with the torsional stiffness of the coupler, acts to modify various undesired oscillation mode shapes in the BHA 20, including stick/slip modes and/or HFTO modes. For example, each coupler 50 includes one or more slots 54 that extend along the periphery (circumference) of the coupler body 52 in a direction that is perpendicular, generally perpendicular or only slightly deviated from the perpendicular direction to a longitudinal axis of the coupler body 52, allowing a degree of lateral bending. The slots 54 may extend around the entire periphery or the circumference of the coupler body as shown in
Modification of torsional oscillation mode shapes is achieved by modifying the oscillation properties of the BHA 20 (or other borehole string or portion thereof) by placing a torsionally stiff and bending flexible downhole component (e.g., the coupler 50) at a predetermined location within the BHA 20. The coupler 50 is placed in the BHA 20 in a way that assures detrimental torsional oscillations are not excited or that the location of high amplitudes of detrimental torsional oscillation modes appear at a location in the BHA that includes a damping device. The damping device dampens the torsional oscillation and removes oscillational energy from the BHA 20. The damping device dissipates the rotational (oscillational) energy, such as by transforming rotational energy into heat. At the same time, the torsionally stiff coupler 50 is bending flexible to allow for directional drilling, including drilling with high borehole build rates (borehole inclination).
The coupler may be used in the BHA 20 in conjunction with a damping device, or without a damping device. In an embodiment, if a damping device is not present, the coupler 50 is used to ensure that detrimental (undesired) torsional oscillation modes appear at locations in the BHA 20 where no sensitive downhole components are located, such as sensitive formation evaluation measurement devices (e.g. nuclear tools, acoustic tools, NMR tools, MWD tools, etc.).
HTFO modes can arise due to various factors, such as cutting forces at a drill bit or other cutting structure. Certain vibratory mode shapes can be induced by various cutting forces at the drill bit 22 (e.g., harmonic excitation forces and impacts), and by self-excitation of vibration due to falling aggressiveness of the drill bit 22 relative to angular velocity.
A downhole system and borehole string, such as the drill string 12 of
Severe vibrations in drill strings and bottom hole assemblies during drilling operations can be caused by cutting forces and/or mass imbalances in downhole tools such as drilling motors. Such vibrations can result in reduced rate of penetration, reduced quality of the borehole, reduced quality of measurements made by tools of the bottom hole assembly, and can result in wear, fatigue, and/or failure of downhole components. Different vibrations exist, such as lateral vibrations, axial vibrations, and torsional vibrations. For example, stick/slip of the whole drilling system and HFTOs are both types of torsional vibrations. The terms “vibration” and “oscillation” are used with the same broad meaning of repeated and/or periodic movements or periodic deviations of a mean value, such as a mean position, a mean velocity, and a mean acceleration. These terms are not meant to be limited to harmonic deviations, but may include all kinds of deviations, such as, but not limited to periodic, harmonic, and statistical deviations.
Torsional vibrations may be excited by self-excitation mechanisms that occur due to the interaction of the drill bit 22 or any other cutting structure (e.g., a reamer bit) and the formation. The main differentiator between stick/slip and HFTO is the frequency and typical mode shapes: For example, HFTO have a frequency that is typically above 50 Hz compared to stick/slip torsional vibrations that typically have frequencies below 1 Hz. HFTO modes that can be modified using the coupler 50 may lie in a range between of 50 Hz and 500 Hz, but are not so limited. The excited mode shape of stick/slip is typically a first mode shape of the whole drilling system, whereas the mode shape of HFTOs can be of higher order and are commonly localized to smaller portions of the drill string 12.
Mode shapes are modified due to the bending flexibility (which affects lateral mode shapes) and torsional stiffness (which affects torsional mode shapes) of the coupler 50. For example, the torsional stiffness can be selected (e.g., by selecting specific slot dimensions in the coupler) to change or affect the frequency of a mode shape that arises in a drill string, the distance between a maximum and minimum of a mode shape, the location of a maximum and/or minimum along the string, the amplitude of the maximum and minimum, and others. By controlling the distance to the bit and/or location in the BHA, the coupler 50 can tune or modify mode shapes so that maxima and minima occur at locations conducive to inclusion of damping devices or damping elements. Furthermore, the location of maxima and minima can be shifted to minimize vibrations at selected positions along the string (e.g., positions with less sensitive downhole components). In addition, the maxima and minima locations can be controlled to increase or maximize amplitude at locations of damping elements.
Exemplary mode shapes are further discussed in US Patent Publication No. 2021/0079738 A1, which is referred to above. Additional examples of mode shapes are discussed in US Patent Publication No. 2018/0252089 A1, assigned to Baker Hughes, a GE Company LLC, and entitled “Method to Mitigate Bit Induced Vibrations by Intentionally Modifying Mode Shapes of Drill Strings by Mass or Stiffness Changes”, which is incorporated by reference herein in its entirety. Optimal placement of the coupler may be achieved by simulating torsional oscillations in the borehole string using a mathematical algorithm, such as an algorithm described in US Patent Publication No. 2018/0252089 A1. The simulation provides mode shapes for different torsional oscillation modes along a borehole string, as displayed in
In an ideal case, the coupler body 52 has a torsional stiffness that corresponds to a solid tubular (drill collar) with corresponding material properties, length, outer diameter and inner diameter (diameter of inner bore) and a bending flexibility that is sufficient to allow bending according to a borehole (inclination) build rate of, for example, 15 degrees per 100 feet of borehole length. As a torsional stiff downhole component is usually also bending stiff, or a bending flexible downhole component is usually also torsional flexible, the coupler 50 includes various structural modifications as compared to a solid tubular, to get as close to the desired coupler body properties as possible. Examples of such modifications are shown in
The coupler body 52 may be configured to relay power and/or communications transmitted through a borehole string. For example, the coupler includes an internal bore, channel, or conduit 53 for an electrical connection (e.g., wire or cable) or other connection (e.g., fiber optic).
The coupler 50 includes any suitable connection mechanism or component that allows the coupler 50 to be connected to other string components. For example, the coupler includes a box connector 58 having internal threading, and a pin connector 60 having external threading.
The slots 54 may extend around the entire periphery or circumference of the coupler body 52, but are not so limited. For example, a slot 54 may have any desired angular position and/or angular extent. An “angular position” may be defined in a plane that is orthogonal or generally orthogonal (e.g., within 5 degrees) to the axis A (such as a plane position indicated by line C) and extends in the radial direction r
A cross-section of the coupler 50 in the plane indicated by line C is illustrated in
In an embodiment, the slots 54 may define a plurality of planes, where each of the plurality of planes is generally orthogonal to the axis A. In this embodiment, the planes are not exactly parallel to each other, but may form a small angle relative to each other, such as an angle between 0.1 degrees and 5 degrees, or between 0.1 degrees and 10 degrees.
In an embodiment, the plurality of slots 54 defines a density of slots. The density of slots is defined by a number of slots along a certain length of the coupler; for example, the density of slots may be 5 slots per meter (m) length of the coupler body, or 10 slots per meter length of the coupler body. The plurality of slots have a width W. The sum of the width W (total width) of each of the plurality of slots allows for defining a density of width. The density of width is defined by the total width along a certain length of the coupler body 52 (e.g., the density of width may be up to 0.5 meters, up to 0.4 meters, or up to 0.3 meters per meter length of the coupler body 52. It is noted the plurality of slots 54 may not all have the same width W, as the with may vary from one slot 54 to a neighboring slot 54. In other examples, groups of slots 54 in the plurality of slots 54 may have a first width W1 and another group in the plurality of slots may have a second width W2.
Each slot 54 has a depth D measured along a radial direction r, a width W measured along an axial direction (i.e., the direction of the axis A) and an angular extent αe along the circumference of the coupler body 52, which may have any suitable value. The depth D may be defined relative to a thickness T of the coupler body wall in the radial direction r, for example, as a percentage or proportion of the thickness T, or as a ratio of depth D to thickness T (D/T). For example, D/T could range from 1/10 to 9/10, and would be influenced by the torque capacity and the desired axial load capacity of the coupler 50. The depth D and width W are selected to impart a desired amount of flexibility based on expected modes and/or mode shapes. For example, the desired amount of flexibility may be a selected bending stiffness that is less than a selected threshold. The depth D defines a central support portion 61 of the coupler 50. The central support portion 61 defines a central support wall around the fluid conduit. The central support wall having a thickness S in radial direction r. The depth D of the slot and the thickness S of the central support wall defines the thickness T of the coupler wall. The depth D may be defined relative to the thickness S of the central support wall (D/S).
A width W may be selected based on a ratio W/P of the width W to a distance P (defined by leftover material or defined by a partition wall 57 between adjacent or neighboring slots 54). For example, the ratio may range from 1/10 to 9/10, or may be larger than one, in such a way that maximum torsional stiffness is maintained. Distances P can be regular or constant, but are not so limited. Generally, a greater D or higher D/T and greater W or higher W/P coincide with smaller bending stiffness, and a smaller P coincides with smaller bending stiffness. Alternatively, the width W may be selected based on a ratio of the width W to the length L of the coupler body 52 may be selected (W/L).
It is noted that there may be any number of slots 54 having any desired angular position αs and angular extent αe. In an embodiment, the coupler 50 includes a plurality of slots 54, which have the same angular extent and angular position. In other embodiments, a slot 54 has a different angular extent and/or angular position relative to one or more other slots 54 at the same axial position (i.e., same location along the axis A) or at different axial positions. The coupler body 52 may be formed from an integral block of material (e.g., steel, stainless steel, Inconel, Titanium, etc.). That is, the slots 54, the internal bore 56, and the fluid conduit are manufactured in the coupler body 52 without using any mechanical connections, such as threads, clamps, welds, etc.
As shown in
In an embodiment, the coupler body 52 and the first and second threaded coupling portions 56 and 60 are manufactured from one integral piece of material. The coupler body 52 promotes bending by the slotted configuration. Bending in this context refers to a longitudinal axis of the first solid annular portion 59a tilting relative to a longitudinal axis of the second solid annular portion when a bending moment is applied over the length L of the coupler body 52.
The coupler body 52 may have any suitable length L, slot width W, wall thickness T, partition wall thickness P, central support wall thickness S, slot depth D and/or other dimensions. In an embodiment, the length L of the coupler body 52 may be between 1 m and 2 m and the width W may be 20 mm, while a thickness T of the partition wall 57 may also be 20 mm. The coupler body 52 may have an outer diameter of around 6¾ inch (170 mm) and an inner diameter of around 1.5 inch (40 mm), leaving around 2.5 inch (65 mm) for the thickness T of the coupler body wall. The slot depth D may be at least 10% of the thickness T of the coupler body wall. In embodiments the slot depth may be at least 20%, 30%, 40%, 50%, or 60% of the thickness T of the coupler body wall. Correspondingly, the thickness S of the central support wall may be smaller than or equal to 90%, 80%, 70%, 60%, or 40% of the thickness T of the coupler body wall. The coupler body 52 including the slots 54 (slotted area of the coupler body 52) may include 20 slots along a length of 0.8 m, leaving 0.2 m for the annular portions 59a and 59b at a coupler body length of 1 m. The coupler 50 may have any desired number of slots, for example, more than 20 slots (e.g., 30 slots or 40 slots). The coupler body 52 may be longer or the width of the slots may be smaller. In an embodiment, the slots may be larger than 20 mm, such as 30 mm, 35 mm, or 40 mm. The thickness P of the partition walls 57 may be greater than 20 mm, such as mm, 35 mm or 40 mm. The thickness P of the partition walls may be greater or smaller than the width of the slots 54. In an embodiment, the width W of the slots 54 and/or the thickness of the partition walls 57 may vary along the longitudinal axis A of the coupler body 52. In an embodiment, the width W of the slots 54 is large enough to ensure that, under bending, the opposing ends of the slots along the longitudinal axis of the coupler body 52 are not contacting.
The greater the slot width W, the higher the bending flexibility, but the lower the torsional stiffness. Therefore, in an embodiment, the number of slots 54, the width of the slots 54 and the thickness of the partition walls 57 are optimized. Optimization of the configuration of the coupler body 52 may be performed by a using simulation algorithms. The coupler body 52 may be longer than 2 m, such as 4 m or 5 m. However, the goal is to design a coupler body 52 that has sufficient torsional stiffness and sufficient bending flexibility while being as short as possible to ensure sensors in a BHA are located in a borehole string as close as possible to a drill bit.
In an embodiment, the coupler 50 includes a flexible material, such as a rubber material or an elastomer, which at least partially fills one or more slots 54. For example, as shown in
In an embodiment, one or more slots 54 include a stress relief feature, which is provided to relieve stress on regions of the coupler body 52 when the coupler 50 bends. Such stress relief facilitates bending and reduces the potential for damage to the body 52.
In an embodiment, the stress relief feature is in the form of one or more rounded or curved edges at an outer end and/or at an inner end of the slot 54. For example, as shown in
Another example of a stress relief feature is shown in
At block 71, a coupler 50 is installed at a borehole string, such as the drill string 12. For example, the coupler 50 is connected at one end to a downhole component (e.g., the LWD tool 30) and connected at another end to another downhole component (e.g., the stabilizer 32). The borehole string may include a damping device (e.g., the damping device 34). A coupler may be installed at any number of locations (including more than one coupler) and connected to any desired components. For example, as shown in
At block 72, the drill string 12 is disposed in a borehole, and the string (or portions thereof) is rotated as part of a drilling operation.
At block 73, during operation, each coupler 50 supports damping of undesired oscillations, such as HTFO modes. As discussed above, the dimensions of the slots are selected to aid damping selected modes or mode shapes, such as HFTOs above about 50 Hz. For example, the coupler shifts a maximum of the mode shape to be at or near the location of a damping device.
Set forth below are some embodiments of the foregoing disclosure:
In connection with the teachings herein, various analyses and/or analytical components may be used, including digital and/or analog systems. The system may have components such as a processor, storage media, memory, input, output, communications link (wired, wireless, pulsed mud, optical or other), user interfaces, software programs, signal processors (digital or analog) and other such components (such as resistors, capacitors, inductors and others) to provide for operation and analyses of the apparatus and methods disclosed herein in any of several manners well-appreciated in the art. It is considered that these teachings may be, but need not be, implemented in conjunction with a set of computer executable instructions stored on a computer readable medium, including memory (ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, hard drives), or any other type that when executed causes a computer to implement the method of the present invention. These instructions may provide for equipment operation, control, data collection and analysis and other functions deemed relevant by a system designer, owner, user or other such personnel, in addition to the functions described in this disclosure.
One skilled in the art will recognize that the various components or technologies may provide certain necessary or beneficial functionality or features. Accordingly, these functions and features as may be needed in support of the appended claims and variations thereof, are recognized as being inherently included as a part of the teachings herein and a part of the invention disclosed.
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 borehole, and/or equipment in the borehole, 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.
This application claims the benefit of U.S. Provisional Patent Application Ser. No. 63/351,002 filed Jun. 10, 2022, the disclosure of which is incorporated herein by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 63351002 | Jun 2022 | US |
