US20250327365A1

US20250327365A1 - Non-contact gyroscopic centralizer tools and methods of use

Info

Publication number: US20250327365A1
Application number: US18/642,699
Authority: US
Inventors: Saleh ALHUMAID; Basil ALSUGAIR
Original assignee: Saudi Arabian Oil Co
Current assignee: Saudi Arabian Oil Co
Priority date: 2024-04-22
Filing date: 2024-04-22
Publication date: 2025-10-23

Abstract

A well system includes a wellhead installation arranged at a surface location, a wellbore extending from the wellhead installation and being at least partially lined with casing, a downhole tool arranged within the wellbore and attached to a conveyance extending from the wellhead installation, and a non-contact auto centralizer attached to the conveyance. The non-contact auto centralizer includes a detecting unit operable to detect a deviation of at least one of the conveyance and the downhole tool from a predefined center of the casing, and a re-centering unit including one or more propellers operable to re-center the at least one of the conveyance and the downhole tool toward the predefined center.

Description

FIELD OF THE DISCLOSURE

The present disclosure relates generally to wellbore intervention operations and, more particularly, a system and method for centralizing conveyances and attached downhole tools within a wellbore tubing during intervention operations.

BACKGROUND OF THE DISCLOSURE

In the oil and gas industry, downhole tools are often deployed downhole on a conveyance to conduct various well intervention operations. At least one challenge in running downhole tools is maintaining the conveyance and the attached downhole tool centered in the wellbore. During downhole descent, for instance, the conveyance and attached downhole tool can each exhibit uncontrolled movement, potentially leading to catastrophic consequences such as severing of the conveyance, which could lead to lodging the downhole tool within the wellbore, and contact with the inner walls of the wellbore (e.g., casing, production tubing, etc.), which leads to scratches and damage to the walls, and damage to the downhole tool.
Conventional solutions to this problem include using centralizers to constantly (or selectively) centralize the downhole tool and conveyance in the wellbore. Some centralizers, for example, employ hydraulic arms that extend to directly contact the inner wall of the wellbore during use. Wells today, however, often feature internal coatings, such as glass reinforced epoxy (GRE), and impose strict requirements against any friction applied to the inner tubing surface. Consequently, passive centralized interventions, even with friction-reduced centralizers like rollers, are deemed unacceptable due to the risk of damaging the tubing's internal coating. Moreover, in scenarios involving heavy crude applications where sticky and dense oil can accumulate on tubing walls, conventional roller-based centralizers become unreliable, impeding successful well interventions.
There is, therefore, a need to provide an innovative slickline centralization solution during well intervention operations that overcomes the limitations of current centralizers.

SUMMARY OF THE DISCLOSURE

Various details of the present disclosure are hereinafter summarized to provide a basic understanding. This summary is not an extensive overview of the disclosure and is neither intended to identify certain elements of the disclosure, nor to delineate the scope thereof. Rather, the primary purpose of this summary is to present some concepts of the disclosure in a simplified form prior to the more detailed description that is presented hereinafter.
According to an embodiment consistent with the present disclosure, a well system is disclosed and includes a wellhead installation arranged at a surface location, a wellbore extending from the wellhead installation and being at least partially lined with casing, a downhole tool arranged within the wellbore and attached to a conveyance extending from the wellhead installation, and a non-contact auto centralizer attached to the conveyance. The non-contact auto centralizer including a detecting unit operable to detect a deviation of at least one of the conveyance and the downhole tool from a predefined center of the casing, and a re-centering unit including one or more propellers operable to re-center the at least one of the conveyance and the downhole tool toward the predefined center.
According to another embodiment consistent with the present disclosure, a method for centralizing a conveyance in a wellbore during a wellbore intervention operation is disclosed and includes the steps of introducing a downhole tool into a wellbore extending from a wellhead installation arranged at a surface location, the downhole tool being attached to the conveyance, and the wellbore being at least partially lined with casing, introducing a non-contact auto centralizer attached to the conveyance simultaneously with the downhole tool, the non-contact auto centralizer including a detecting unit and a re-centering unit including one or more propellers, detecting a deviation of at least one of the conveyance and the downhole tool from a predefined center of the casing with the detecting unit, and operating the one or more propellers and thereby re-centering the at least one of the conveyance and the downhole tool toward the predefined center.
Any combinations of the various embodiments and implementations disclosed herein can be used in a further embodiment, consistent with the disclosure. These and other aspects and features can be appreciated from the following description of certain embodiments presented herein in accordance with the disclosure and the accompanying drawings and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic view of an example well system that may incorporate the principles of the present disclosure.

FIG. 2 illustrates an example schematic representation of a section of the wellbore lined with the string of casing.

FIG. 3 is an enlarged cross-sectional view of the wellbore depicting an example of the gyroscopic centralizer tool of FIG. 1 , according to one or more embodiments.

FIGS. 4A-4C graphically depict a scenario where the conveyance deviates from a predetermined path and is subsequently returned to the predetermined path using the gyroscopic centralizer tool of FIG. 3 , according to one or more embodiments.

FIG. 5 is a schematic flow chart of an example method for centralizing a conveyance in a wellbore during a wellbore intervention operation.

DETAILED DESCRIPTION

Embodiments of the present disclosure will now be described in detail with reference to the accompanying Figures. Like elements in the various figures may be denoted by like reference numerals for consistency. Further, in the following detailed description of embodiments of the present disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the claimed subject matter. However, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Additionally, it will be apparent to one of ordinary skill in the art that the scale of the elements presented in the accompanying Figures may vary without departing from the scope of the present disclosure.
Embodiments in accordance with the present disclosure generally relate to a system and method for centralizing conveyances and attached downhole tools within a wellbore tubing during intervention operations. Disclosed is a well system that can include a wellhead installation arranged at a surface location, and a wellbore extends from the wellhead installation and is at least partially lined with casing. A downhole tool may be arranged within the wellbore and attached to a conveyance extending from the wellhead installation. A gyroscopic centralizer tool is also attached to the conveyance and conveyed into the wellbore with the downhole tool. The gyroscopic centralizer tool includes a detecting unit operable to detect a deviation of at least one of the conveyance and the downhole tool from a predefined center of the casing, and a re-centering unit including one or more propellers operable to re-center the at least one of the conveyance and the downhole tool toward the predefined center.
FIG. 1 is a schematic view of an example well system 100 that may incorporate the principles of the present disclosure. As illustrated, the well system 100 (hereafter “the system 100”) includes a wellhead installation 101 installed at a surface location 104, such as the Earth's surface, and a wellbore 106 extends from the wellhead installation 101 and penetrates one or more subterranean formations 108. The wellbore 106 may be cased, open hole, contain tubing, and/or may generally be characterized as a hole in the ground having a variety of shapes and/or geometries as are known to those of skill in the art. In FIG. 1 , the wellbore 106 is shown lined with a string of casing 109 that may be secured in place with cement. While not shown in FIG. 1 , in at least one embodiment, a string of production tubing may be extended within the casing 109.
While the system 100 is depicted in FIG. 1 as a land-based system, the principles described herein are equally applicable to subsea operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure.
The system 100 may be configured for downhole well intervention operations. As illustrated, the system 100 may include a wellhead 102, a blowout preventer (BOP) 110 operatively coupled to (e.g., bolted or clamped) the wellhead 102, and a lubricator 112 may be operatively coupled to (e.g., bolted or clamped) the BOP 110. While not shown, additional components may be positioned between the BOP 110 and the wellhead 102 or between the BOP 110 and the lubricator 112, such as a casing head spool, a tubing head spool, etc. Accordingly, the example arrangement of the wellhead 102, the BOP 110, and the lubricator 112 in FIG. 1 should not be considered a limitation of the present disclosure, rather many variations of said arrangement may be included in the system 100, without departing from the scope of the disclosure.
The BOP 110 may include a plurality of valves operable to control hydrocarbon production from the subterranean formation(s) 108. The lubricator 112 may be an elongate, high-pressure pipe or tubular fitted to the top of the BOP 110 and configured to provide a means for introducing downhole tools and assemblies into the wellbore 106 via a conveyance 114. Examples of the conveyance 114 include, but are not limited to, slickline, wireline, and coiled tubing. The lubricator 112 is a pressure-controlled device used to initially house downhole tools and assemblies and create a seal between the outside environment and the pressurized environment in the well.
The conveyance 114 may be coiled (wound) onto a large drum 116 and routed through one or more pulleys or sheaves 118 to be introduced into the lubricator 112 at a stuffing box 120 provided at the top of the lubricator 112. The stuffing box 120 comprises a high-pressure grease-injection section and includes various sealing elements used to seal about the conveyance 114 as it is fed into and out of the lubricator 112. An operator rotates the drum 116 to alternately lower (unspool) or raise (spool) the conveyance 114.
The system 100 may also include a downhole tool 122 configured to be introduced into the wellbore 106 (e.g., within the casing 109 or production tubing arranged within the casing 109) to undertake one or more downhole operations. The downhole tool 122 may comprise a variety of downhole tools, devices, mechanisms, and assemblies capable of completing a variety of downhole operations. In some embodiments, the downhole tool 122 may comprise a single downhole tool, but could alternatively comprise a tool string or a bottom hole assembly (BHA) comprised of multiple tools and/or devices arranged in series. Examples of the downhole tool 122 include, but are not limited to, a fluid sampler, a completion tool, a drilling tool, a stimulation tool, an evaluation tool, a safety tool, an abandonment tool, a packer, a bridge plug, a setting tool, a perforation gun, a casing cutter, a flow control device, a sensing instrument (e.g., a pressure gauge, a temperature gauge, etc.), a data collection device and/or instrument, a measure while drilling (MWD) tool, a logging while drilling (LWD) tool, a drill bit, a reamer, a stimulation tool, a fracturing tool, a production tool, combinations thereof, and the like.
To convey the downhole tool 122 into the wellbore 106, the downhole tool 122 is coupled to the conveyance 114 and placed within the lubricator 112. The lubricator 112 is then pressurized to at or above the pressure of the wellbore 106, and once properly pressurized, one or more of the valves on the BOP 110 is opened to enable the downhole tool 122 to descend into the wellbore 106 on the conveyance 114 via the BOP 110. In some embodiments, the downhole tool 122 simply falls into the wellbore 106 on the conveyance 114 under gravitational forces. In other embodiments, however, the downhole tool 122 may be pumped into the wellbore 106 on the conveyance 114 under pressure. In yet other embodiments, such as embodiments where the conveyance 114 comprises coiled tubing, the downhole tool 122 may be advanced into the wellbore 106 through axial loading provided by the coiled tubing.
To remove the downhole tool 122 from the wellbore 106, the conveyance 114 is retracted and the installation process is reversed.
In at least one embodiment, the downhole tool 122 comprises or otherwise includes a pressure gauge operable to collect downhole pressure data. To be able to obtain proper (accurate) pressure data, it is preferable to maintain the pressure gauge at the center of the wellbore 106 during its descent downhole. Keeping the pressure gauge at the center of the wellbore 106 also helps avoid damaging the gauge and the inner walls of the wellbore 106 (e.g., the casing 109). Moreover, it is similarly preferable to maintain the conveyance 114 at the center of the wellbore 106 so as to not inadvertently twist or sever the conveyance, or likewise damage the inner wall of the wellbore 106.
According to embodiments of the present disclosure, the system 100 may further include a gyroscopic centralizer tool, referred to herein as a “non-contact auto centralizer” 124, operable to detect deviation from the center (or centerline) of the wellbore 106, and further operable to re-centralize the conveyance 114 and the downhole tool 122 within the wellbore 106 as needed. As will be appreciated, this will allow for well intervention without touching the internal walls of the wellbore 106 or casing 109, and thereby helping to avoid damage to the downhole tool 122, the conveyance 114, the inner walls of the wellbore 106, or any combination thereof.
FIG. 2 illustrates an example schematic representation of a section of the wellbore 106 lined with the string of casing 109. FIG. 2 also shows an actual pathway 202 of the conveyance 114 (FIG. 1 ) as it descends within the casing 109 as compared to a desired pathway or centerline 204 of the wellbore 106 (and casing 109). Preferably, the conveyance 114 will descend within the wellbore 106 along or substantially along the centerline 204. In FIG. 2 , however, the conveyance 114 is conveyed into the wellbore 106 without a centralizer and, therefore, does not follow the intended/designed path along the centerline 204.
As mentioned above, the conventional use of downhole conveyances without any centralizer can pose a significant risk of uncontrolled movement, potentially leading to catastrophic consequences such as severing of the conveyance, contact with the tubing walls, which leads to scratching and damaging of the walls, and possible damage to the payload (e.g., the downhole tool 122 of FIG. 1 ). Further, conventional solutions, such as employing hydraulic arm-based centralizers, face limitations in compatibility with newer generation wells. These wells often feature internal coatings, such as glass reinforced epoxy (GRE), and impose strict requirements against any friction applied to the inner surfaces of the casing 109. Consequently, passive centralized interventions, even with friction-reduced centralizers like rollers, are deemed unacceptable due to the risk of damaging the tubing's internal coating. Moreover, in scenarios involving heavy crude applications where sticky and dense oil can accumulate on tubing walls, conventional roller-based centralizers become unreliable, impeding successful well interventions. The drawbacks of the conventional systems highlight the pressing need for a system or mechanism for centralizing a conveyance in wellbore tubing.
FIG. 3 is an enlarged cross-sectional view of the wellbore 106 depicting an example of the non-contact auto centralizer 124 (hereafter the “auto centralizer”) that may be used in accordance with the principles of the present disclosure. The conveyance 114 traverses the length of the casing 109 and provides a means for conveying the downhole tool 122 into the wellbore 106. In some applications, the inner wall of the casing 109 may be coated with
GRE and may otherwise be internally coated to enhance durability and prevent corrosion. The auto centralizer 124 may be operable to help centralize the conveyance 114 within the wellbore 106 and, more particularly, within the casing 109 (or another tubing within the wellbore 106). As a result, the auto centralizer 124 may also be used to help centralize the downhole tool 122 (e.g., a “payload”) within the wellbore 106 without any interaction (i.e., in a contactless manner) with the inner wall of the casing 109.
As illustrated, the auto centralizer 124 may include a detecting unit 302 operable to detect a deviation of the conveyance 114 from a predefined center of the casing 109 (e.g., the centerline 204 of the wellbore 106), which may correspond to an intended/designed path of traversal for the conveyance 114. In an example, the detecting unit 302 may include one or more gyroscopes 304 configured to detect deviations of the conveyance 114 from the center of the casing 109. The determination of deviation from a predefined center of the casing 109 may involve a series of steps aimed at evaluating the offset between the actual path (also referred as current/real path) of the conveyance 114 and its central path (also referred as intended/designated path) within the casing 109.
In an embodiment, determining deviation of the conveyance 114 may include real-time monitoring of the current X and Y coordinates of the conveyance 114 as it traverses the length of the wellbore 106 (e.g., the casing 109 or other tubing arranged within the wellbore 106). In one or more embodiments, a measurement point may be considered on the conveyance 114 that is substantially close to the downhole tool 122. Such a measurement point may be predetermined during measurement of the reference X and Y coordinates so that all future measurements of the “current” or real-time X and Y coordinates correspond to the same measurement point on the conveyance 114. This continuous monitoring enables the detecting unit 302 to track the real-time movement of the conveyance 114 in relation to the reference coordinates, and provide dynamic feedback on the position of the conveyance 114 (or the measurement point on the conveyance 114) within the casing 109.
The wellbore 106 can be deviated from true vertical, slanted, or completely horizontal. The gyroscope(s) 304 may be employed to detect deviations of the conveyance 114 from the predefined center of the Wellbore 106 (e.g., the casing 109) and otherwise configured to detect deviations in the X and Y directions. More specifically, the gyroscope(s) may be operable to measure real-time X and Y coordinates, which are compared against the original wellbore trajectory (e.g., a Deviation Survey or Well Trajectory) of the well. As discussed below, the Well Trajectory is a well-defined document generated when first drilling the well, which includes the X and Y coordinates of the wellbore 106 as the well deepens into the earth. As shown in the enlarged inset graphic, the gyroscopes 304 can include one or more first gyroscopes 304 a arranged and configured to detect deviations in the X direction, and one or more second gyroscopes 304 b arranged and configured to detect deviations in the Y direction. The detecting unit 302 provides valuable data by measuring the deviation around a specific axis (e.g., the centerline 204 of the wellbore 106), and such deviation information enables the auto centralizer 124 to determine the magnitude of the deviation and take timely course-corrective actions.
In one or more embodiments, the auto centralizer 124 may utilize the center of gravity of the downhole tool 122 as the measurement point for detecting deviation. This ensures that any detected deviation is measured relative to the gravitational center of the downhole tool 122, thereby providing a stable and gravity-centric reference for re-centering actions. In other embodiments, the auto centralizer 124 may utilize the gyroscopic center as the measurement point for detecting deviations. This approach enhances precision by aligning the monitoring process with the gyroscopic characteristics of the conveyance 114 during well intervention operations. The flexibility to choose between various reference/measurement points allows the auto centralizer 124 to adapt to varying conditions and requirements in different wellbore scenarios and different wellbore operations. For instance, if the downhole tool 122 is heavier than a predefined weight threshold, then the measurement point may be chosen to be substantially close to the downhole tool 122 or may even be the center of gravity of the downhole tool 122. In another example, if the downhole tool 122 weighs less than a predefined weight threshold, the measurement point may be the gyroscopic center or any point between the gyroscopes and the downhole tool 122.
In one or more embodiments, initially determining the reference X and Y coordinates of the wellbore 106 (and the casing 109) may include positioning the detection unit 302 atop a reference valve, for example, the crown valve of the BOP 110 (FIG. 1 ). Once the detection unit 302 becomes perfectly vertical and aligned with the centerline 204 (FIG. 2 ) of the wellbore 106, the orientation and reference coordinates will be recorded. The reference coordinates in terms of X and Y may represent the center of the casing 109 and may be visually represented as a curvilinear path or a straight line. For example, the original drilling operation of the well may have captured the deviation of the wellbore 106 from true vertical, which can be found in what is called the Deviation Survey or Well Trajectory. Measuring the Deviation Survey involves leveraging a gyroscopic application. From the Deviation Survey, it is possible to calculate the X and Y coordinates that represent the center of the wellbore 106 for each depth interval throughout the entire duration of the well intervention path. In an embodiment, such depth intervals may also be predetermined based on the characteristics of the casing 109 and/or the intervention operations.
In some embodiments, the detection unit 302 may be programmed and otherwise configured to continuously monitor current (real-time) X and Y coordinates, ensuring a comprehensive assessment of the movement of the conveyance 114 during the entire wellbore intervention operation. The gyroscopes 304 a,b allow for a synergistic analysis, considering both translational (X and Y coordinates) and rotational (angular deviations) components. Such a combined approach provides a detailed representation of the position of the conveyance 114 within the wellbore 106 (e.g., the casing 109). Moreover, in one or more embodiments, the auto centralizer 124 may further incorporate one or more additional sensors or units for increased accuracy, without departing from the scope of the disclosure. In such embodiments, such sensors can include, but are not limited to, accelerometers, magnetometers, or any suitable sensing technology capable of contributing to the accurate determination of the deviation of the conveyance 114. Further, in at least one embodiment, the auto centralizer 124 may include a pressure sensor to enable the system to dynamically adjust centralization in response to fluctuations in wellbore pressure.
Determining the deviation of the conveyance 114 may include comparing the reference X and Y coordinates of the wellbore 106 (e.g., the casing 109 or another tubing arranged within the wellbore 106) with the current (real-time) X and Y coordinates of the conveyance 114 as the conveyance 114 travels (descends) within the casing 109. This step may enable quantification of the deviation, offering insights into how far the conveyance 114 has deviated from its intended path within the casing 109. The quantification also enables determination of the combined thrust (force) required to re-center the conveyance 114, as discussed below.
In addition, determining the deviation of the conveyance 114 may further include determining if the current (real-time) X and Y coordinates of the conveyance 114 have deviated beyond a predetermined deviation threshold with respect to the reference X and Y coordinates. The auto centralizer 124 is configured to adjustably set the predetermined deviation threshold to establish acceptable limits for deviation. The customization of predetermined deviation thresholds before beginning the wellbore intervention operation ensures that corrective measures are triggered only when the measured deviations exceed the predetermined deviation threshold.
In some embodiments, the predetermined deviation threshold can be about +/−0.05 inches from the reference coordinates (i.e., along X- and Y-axes). Further, in an example, the predetermined deviation threshold for detecting deviation is adjustable based on wellbore conditions and characteristics. For example, the threshold-based analysis may be crucial for distinguishing significant (unacceptable) deviations from minor variations in the position of the conveyance 114. If the current X and Y coordinates exceed the predetermined deviation threshold, that indicates a notable deviation from the expected path within the casing 109. This approach provides practical criteria for identifying deviations that may require attention or corrective actions, offering a systematic and proactive method for monitoring the trajectory of the conveyance 114.
As illustrated, the auto centralizer 124 may further include a re-centering or “turbine-powered” unit 306 configured to rectify (correct) deviations in the positioning of the conveyance 114 within the casing 109. The re-centering unit 306 functions as a dynamic response mechanism to promptly address any detected deviation and thereby ensure the continuous alignment of the conveyance 114 along its intended/planned path or the center of the casing 109. In some embodiments, as illustrated, the re-centering unit 306 may include one or more motorized fans, blades, turbines, or propellers 308 (collectively referred to herein as “propellers 308”). As used herein, the term “propellers” refers to rotating blades or turbines powered by a motor. The propellers 308 play a pivotal role in providing controlled thrust in predetermined directions upon detection of a deviation beyond the predetermined deviation threshold.
As shown in the enlarged inset graphic of FIG. 3 , the propellers 308 may include four propellers, namely, a first propeller 308 a, a second propeller 308 b, a third propeller 308 c, and a fourth propeller 308 d. In other embodiments, there may be only three propellers 308 equidistantly spaced from each other (e.g., 120° apart), or more than four propellers 308, without departing from the scope of the disclosure. In some applications, the number of propellers 308 a-d may depend on the weight of the downhole tool 122. For instance, a heavier payload may require a higher number of propellers 308 a-d, and a lighter payload may require a lower number of propellers 308 a-d.
In some embodiments, each propeller 308 a-d is powered and otherwise driven by a dedicated and discrete motor. In other embodiments, two or more of the propellers 308 a-d may be powered or driven by the same motor. In example operation, the auto centralizer 124 may activate the motor associated with some or all of the propellers 308 a-d, resulting in a precisely controlled thrust that facilitates realignment of the conveyance 114 (and the downhole tool 122) to its intended trajectory. Further, the propellers 308 a-d can be selectively, sequentially, and/or simultaneously activated to precisely control the alignment of the conveyance 114 to the intended path. The coordinated action of the propellers 308 a-d ensures an efficient and targeted response to deviations, enhancing the overall centralization process during well intervention operations.
In one or more embodiments, the auto centralizer 124 includes multiple motors used to drive different sets of propellers 308 a-d. In such embodiments, each motor may be specifically associated with a particular set of propellers 308 a-d. Upon detecting a deviation beyond the predetermined deviation threshold, the auto centralizer 124 may selectively, sequentially, and/or simultaneously activate the motors corresponding to the respective set of propellers 308 a-d. This approach provides independent control over each motorized propeller 308 a-d, allowing for the generation of a controlled and combined thrust in distinct directions with different magnitudes based on the detected deviation. Alternatively, a single motor with a variable frequency drive can be employed. The variable frequency drive facilitates the adjustment of rotational speeds for different propellers 308 a-d based on the nature and extent of the detected deviation. This dynamic capability allows the auto centralizer 124 to modulate the rotational speed of individual propellers 308 a-d, tailoring the thrust generated by each propeller 308 a-d to the precise requirements of the realignment or re-centering process.
In some embodiments, the auto centralizer 124 may provide an elongate housing 310 having a first or “upper” end 312 a and a second or “lower” end 312 b opposite the upper end 312 a. The upper end 312 a may be operatively coupled to the conveyance 114, and the lower end 312 b may be operatively coupled to the downhole tool 122. The gyroscopes 304 a,b and the propellers 308 a-d may be operatively and strategically coupled to the housing 310 at a corresponding locations between the upper and lower ends 312 a,b. In some embodiments, as illustrated, the propellers 308 a-d may be located near the downhole tool 122 and the gyroscopes 308 a-d may be located closer to the upper end 312 a. In other embodiments, however, the gyroscopes 308 a-d may be located near the downhole tool 122 so that the detected deviation of the conveyance 114 represents most accurately the deviation of the downhole tool 122.
The design and configuration of the auto centralizer 124 may take into consideration space limitations of common downhole tubulars (e.g., the casing 109, production tubing, etc.). For instance, existing logging tools can fit in casing having a diameter of about 3.5 inches. In an embodiment, the size of well intervention tools (and therefore the auto centralizer 124) may be adjustable and otherwise capable of being scaled up or down based on the different size limitations of the casing 109.
In an example where the casing 109 exhibits a diameter of about 4.5 inches, an area of over 63 inches squared is available for design considerations of the auto centralizer 124. This space is sufficient to accommodate all the component parts of the auto centralizer 124 and centralize the downhole tool 122 by using the components described herein. Furthermore, as mentioned above, for different applications there can be a varying numbers of propellers 308 a-d in line with one another to provide the necessary forces (thrust) needed to properly centralize the downhole tool 122.
Once the auto centralizer 124 identifies or senses a deviation beyond the predetermined deviation threshold, the auto centralizer 124 may be programmed or otherwise configured to activate one or more of the propellers 308 a-d selectively, sequentially, and/or simultaneously to generate controlled thrust in a specified direction, thus facilitating the precise realignment of the conveyance 114 towards the predefined center of the casing 109. This controlled and selective operation ensures an efficient and accurate response to deviations, which helps maintain optimal alignment throughout the wellbore intervention operation.
If the auto centralizer 124 detects a deviation in the position of the conveyance 114 (or the position of the downhole tool 122) from the predefined center of the casing 109, the auto centralizer 124 may selectively activate specific propellers 308 a-d to generate thrust in a strategically chosen direction to counteract the deviation. For example, if the conveyance 114 (or the downhole tool 122) deviates towards the right of the center of the casing 109, as viewed from the vantage point of FIG. 3 , the auto centralizer 124 can selectively activate one or more propellers 308 a-d on the left side of the housing 310 and thereby generate a thrust toward the leftward direction, effectively steering the conveyance 114 (and the downhole tool 122) back towards the center by offsetting the determined deviation. The magnitude of the mechanical force or thrust generated by the activated propellers 308 a-d may be proportional to the magnitude of the detected deviation. Similarly, the direction of the applied thrust may be dependent on the direction associated with the detected deviation. Alternatively, the auto centralizer 124 may engage all of the propellers 308 a-d simultaneously, each propeller 308 a-d contributing an individual thrust in a designated direction, and thereby resulting in a combined force/thrust that facilitates re-centering of the conveyance 114 in a time-efficient manner.
In an embodiment, the re-centering process may involve multiple re-centering sub-steps each of which reduces the determined deviation in a step-wise manner. In such embodiments, the re-centering process may be iterative and carried out until the deviation falls within accepted limits of the predetermined deviation threshold. Each re-centering sub-step may correspond to an individual or combined thrust from one or more propellers thereby sequentially reducing the deviation in steps and achieving the centralization of the downhole tool 122 in a time and energy efficient manner.
In an embodiment, as the conveyance 114 traverses the casing 109, the auto centralizer 124 continuously monitors its current (real-time) X and Y coordinates. The frequency of such monitoring (and associated computations) can be customized based on the specific requirements and characteristics of the wellbore 106 and the intervention operation, among other factors. For instance, very frequent monitoring may be preferred in situations where deviation thresholds are sensitive or set to very low values. This customization allows the auto centralizer 124 to adapt its monitoring frequency to the specific conditions of the wellbore and/or intervention operations, ensuring a tailored and responsive approach.
In some embodiments, the auto centralizer 124 may include or be communicably coupled to a control unit 314 in communication with the detecting unit 302 and the re-centering unit 306. In particular, the control unit 314 is configured to receive and/or send signals to the detecting unit 302 and the re-centering unit 306, and thus may be configured to control operation of the auto centralizer 124. In some embodiments, the control unit 314 may be remotely located, such as at the well surface location 104 (FIG. 1 ) and communicate with the auto centralizer 124 via any wired or wireless communication means. For example, the control unit 314 may communicate with the auto centralizer 124 via a wire or cable run along or through (within) the conveyance 114. In other embodiments, however, the control unit 314 may be arranged within or coupled to the housing 310 and otherwise located near the detecting unit 302 and the re-centering unit 306.
The control unit 314 is configured to ensure a responsive and accurate realignment of the conveyance 114 based on deviations detected during its traversal within the casing 109. The control unit 314 is further configured to continuously receive signals indicative of the current position of the conveyance 114 and deviations from the detecting unit 302 for logging and pattern recognition purposes.
In some embodiments, it is the control unit 314 that is programmed to control monitoring of the current X and Y coordinates of the downhole tool 122 as the conveyance 114 traverses the casing 109. The control unit 314 may then be programmed or otherwise configured to compare the real-time coordinates with the reference X and Y coordinates of the casing 109 and determine any deviations beyond a predetermined deviation threshold with respect to the reference coordinates. Upon detection of such deviations, the control unit 314 may be programmed or otherwise configured to activate (or send an activating signal to) the propellers 308 a-d. In at least one embodiment, the control unit 314 ensures a continual feedback loop based on signals received from the detecting unit 302, and dynamically adapts to changes in the conveyance 114 trajectory within the casing 109 by sending activating signals to the re-centering unit 306. This real-time responsiveness facilitates prompt and accurate adjustments, ensuring that the auto centralizer 124 adapts effectively to variations in the conveyance 114 or the downhole tool 122 position.
In some embodiments, the control unit 314 may be configured to regulate operation of each propeller 308 a-d, thus facilitating movement of the conveyance 114 and/or the downhole tool 122 towards the predefined center of the casing 109. Further, the control unit 314 may determine an angular force required by the propellers 308 a-d to re-center the conveyance 114 and/or the downhole tool 122. The control unit 314 selectively operates each motorized propeller 308 a-d to generate the controlled thrust, ensuring a precise and effective realignment of the conveyance 114. Additionally, the control unit 314 may be configured to modulate the speed and direction of rotation for each motorized propeller 308 a-d. This precise modulation enables the generation of thrust in a targeted manner, which may be crucial for steering the conveyance 114 and/or the downhole tool 122 towards the central axis of the casing 109. This corrective action, aligned with the nature of the detected deviation, not only ensures timeliness but also enhances the overall efficiency of the realignment process.
In some embodiments, there may be multiple auto centralizers 124 with corresponding detecting units 104 and re-centering units 106 installed along the length of the conveyance 114 at multiple and pre-selected locations. In such embodiments, each auto centralizer 124 may be in communication with the control unit 314, which provides centralized control of each auto centralizer 124. The control unit 314 may be configured to send/receive signals from each gyroscopic centralizer tool 124 and can control the re-centering process not just of the downhole tool 122 at one end of the conveyance 114 but also of the entire or a predetermined length of the conveyance 114. Such an arrangement may be useful in scenarios where the downhole tool 122 is heavier than a weight threshold.
Including multiple auto centralizers 124 may also be useful in applications where there is a higher risk of equipment failure during the wellbore intervention operation. Instead of lifting the conveyance 114 to the well surface 104 (FIG. 1 ) for repair operations, it may be desirable to continue with the wellbore intervention operation, if possible. Therefore, if one auto centralizer 124 fails during the wellbore intervention operation, the other (remaining) auto centralizers 124 may be used for continuous monitoring and re-centralization without having to stall the intervention operation or retrieving the conveyance 114 to the well surface 104. As will be appreciated, including multiple auto centralizers 124 at different (spaced) locations along the conveyance 114 may provide a highly coordinated maneuvering capability of the conveyance 114 and the downhole tool 122 leading to higher re-centering accuracies.
During some wellbore intervention operations, there may be a risk associated with failure or severance of the conveyance 114. For instance, in operations where the conveyance 114 comprises slickline, twisting of the slickline may be identified by increased weight on the surface and resolved by lifting the slickline to the surface and allowing the tool to untwist itself freely and then trying again. According to the present disclosure, however, the auto centralizer 124 may help prevent the likelihood of having downhole twisting occur.
For instance, upon detection of an increased weight and tension of the conveyance 114 at the well surface 104 (FIG. 1 ), which may be indicative of a possible twisting of the conveyance 114, the control unit 314 may be configured to activate a set of propellers 308 a-d. The set of propellers 308 a-d may be located along the length of the conveyance 114 at predetermined locations, and the control unit 314 may automatically activate the propellers 308 a-d with individual (discrete) angular speeds or thrusts in specific directions to generate a clockwise or counter-clockwise angular momentum of the downhole tool 122 about the central axis or the center of the casing 109. This angular momentum results in preventing twisting of the conveyance 114 in the casing 109.
The control unit 314 may be implemented as one or more processors that can be a digital signal processor (e.g., a microprocessor, a microcontroller, or a fixed-logic processor, etc.) configured to execute instructions or logic. The processor may include a general-purpose processor, a special-purpose processor (where software instructions are incorporated into the processor), a state machine, an application-specific integrated circuit (ASIC), a programmable gate array (PGA) including a field PGA, an individual component, a distributed group of processors, and the like.
In some embodiments, the control unit 314 may communicate with a display or graphical user interface (GUI) to display measurement data associated with the wellbore intervention operation, the deviations in X and Y coordinates of the downhole tool 122, the current and reference X and Y coordinates, sensor data, pressure data, depth data, or other parameters. The display or GUI may also indicate the position of the conveyance 114 and the downhole tool 122 within the casing 109 for a user to monitor the well intervention operation.

Working Example

In the context of applying the disclosed embodiments to wellbore intervention operations, FIGS. 4A-4C graphically depict a scenario where the conveyance 114 is deployed within the casing 109, deviates from a predetermined path 402, and is subsequently returned to the predetermined path 402 using the auto centralizer 124 described herein. As the conveyance 114 traverses the casing 109, a gyroscope, serving as the detection unit, determines the alignment of the conveyance 114 with respect to the predetermined path 402 established and based on reference X and Y coordinates. In FIG. 4A, the actual pathway 404 of the conveyance 114 is shown deviated from the predetermined path 402. Upon detecting a deviation from the predetermined path 402, the auto centralizer 124 (FIG. 3 ) initiates an assessment to ascertain whether this deviation exceeds a predetermined deviation threshold. If the detected deviation falls within acceptable limits, i.e., below the predetermined deviation threshold, the auto centralizer 124 continues to monitor the real-time X and Y coordinates of the conveyance 114, maintaining the trajectory. In instances where the deviation exceeds the predetermined deviation threshold, signifying an undesired departure from the predetermined path 402, as depicted in FIG. 4B, the auto centralizer 124 promptly responds by activating one or more of its propellers 308 a-d (FIG. 3 ). Operating the propellers 308 a-d generates controlled thrust in the necessary direction, with the primary goal of rectifying the deviation and guiding the conveyance 114 (and/or payload) back towards the predetermined path 402, as shown in FIG. 4C.
By expeditiously implementing corrective measures to address significant deviations, the auto centralizer 124 effectively mitigates the potential repercussions. These consequences could encompass undesired contact with the tubing walls, leading to damage, or compromising the integrity of the transported tool or payload. The automated corrective process ensures the swift realignment of the conveyance 114 and/or the downhole tool 122 to its intended trajectory, thereby enhancing the efficacy and safety of wellbore intervention operations.
In view of the foregoing structural and functional features described above, example methods will be better appreciated with reference to FIGS. 5 and 6 . While, for purposes of simplicity of explanation, the example methods of FIGS. 5 and 6 are shown and described as executing serially, it is to be understood and appreciated that the present examples are not limited by the illustrated order, as some actions could in other examples occur in different orders, multiple times and/or concurrently from that shown and described herein. Moreover, it is not necessary that all described actions be performed to implement the methods.
FIG. 5 is a schematic flow chart of an example method 500 for centralizing a conveyance in a wellbore during a wellbore intervention operation. As illustrated, the method 500 includes introducing a downhole tool into a wellbore extending from a wellhead installation arranged at a surface location, as at 502. The downhole tool may be attached to the conveyance, and the wellbore may be at least partially lined with casing. The method 500 further includes introducing a non-contact auto centralizer attached to the conveyance simultaneously with the downhole tool, as at 504. The auto centralizer may include a detecting unit and a re-centering unit that includes one or more propellers. The method 500 may further include detecting a deviation of at least one of the conveyance and the downhole tool from a predefined center of the casing with the detecting unit, as at 506. Moreover, the method 500 may further include operating the one or more propellers and thereby re-centering the at least one of the conveyance and the downhole tool toward the predefined center.
Implementations of the present disclosure may realize a variety of advantages. For example, when dealing with internally coated tubings, like glass reinforced epoxy (GRE), the utilization of friction-reduced centralizers, such as rollers, poses a considerable risk. Contact with these centralizers may compromise the internal coating, exposing the pipe to reservoir fluids. Consequently, conventional wellbore intervention practices abstain from deploying tools in internally coated tubings to mitigate such risks. The disclosed system, enables non-contact or contactless centralization and employs at least one gyroscope to ensure precise detection of slickline deviations, allowing for accurate re-centering. Thus, the disclosed embodiments allows oil intervention operations to safely lower a slickline and attached payload (downhole tool) into deeper sections of casing and enables acquisition of crucial reservoir data without the inherent risks.
Further, in heavy crude applications marked by the presence of sticky and dense oil, rollers used in conventional centralizers are prone to rapid obstruction, typically within the initial 1000 feet of the casing. This unreliability impedes effective intervention in heavy crude scenarios. The disclosed embodiments addresses this limitation by ensuring that the system components (e.g., propellers and gyroscopes) are disposed along the conveyance and away from the internal tubing (casing) walls. As a result, the propellers operate in lighter crude environments, with lighter crudes predominantly traveling at the center of the tubing, while heavier crudes slide along the walls.
In addition, the disclosed system allows selectively and/or sequentially activating one or more propellers, ensuring effective centralization during conveyance traversal through the casing. Consequently, the disclosed embodiments overcome limitations of conventional centralizers, providing a contactless centralization mechanism suitable for wells with internal coatings and resistant to heavy crude applications. By enhancing centralization accuracy, automated re-centering, and adaptability, the disclosed system ensures improved safety, reliability, and efficiency in wellbore intervention operations.
The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used herein, for example, the singular forms “a,” “an,” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “contains”, “containing”, “includes”, “including,” “comprises”, and/or “comprising,” and variations thereof, when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.
Terms of orientation are used herein merely for purposes of convention and referencing and are not to be construed as limiting. However, it is recognized these terms could be used with reference to an operator or user. Accordingly, no limitations are implied or to be inferred. In addition, the use of ordinal numbers (e.g., first, second, third, etc.) is for distinction and not counting. For example, the use of “third” does not imply there must be a corresponding “first” or “second.” Also, if used herein, the terms “coupled” or “coupled to” or “connected” or “connected to” or “attached” or “attached to” may indicate establishing either a direct or indirect connection, and is not limited to either unless expressly referenced as such.
The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well.
While the disclosure has described several exemplary embodiments, it will be understood by those skilled in the art that various changes can be made, and equivalents can be substituted for elements thereof, without departing from the spirit and scope of the invention. In addition, many modifications will be appreciated by those skilled in the art to adapt a particular instrument, situation, or material to embodiments of the disclosure without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiments disclosed, or to the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims. Moreover, reference in the appended claims to an apparatus or system or a component of an apparatus or system being adapted to, arranged to, capable of, configured to, enabled to, operable to, or operative to perform a particular function encompasses that apparatus, system, or component, whether or not it or that particular function is activated, turned on, or unlocked, as long as that apparatus, system, or component is so adapted, arranged, capable, configured, enabled, operable, or operative.

Claims

The invention claimed is:

1. A well system, comprising:

a wellhead installation arranged at a surface location;

a wellbore extending from the wellhead installation and being at least partially lined with casing;

a downhole tool arranged within the wellbore and attached to a conveyance extending from the wellhead installation; and

a non-contact auto centralizer attached to the conveyance and including:

a detecting unit operable to detect a deviation of at least one of the conveyance and the downhole tool from a predefined center of the casing; and

a re-centering unit including one or more propellers operable to re-center the at least one of the conveyance and the downhole tool toward the predefined center.

2. The well system of claim 1, wherein the conveyance is selected from the group consisting of slickline, wireline, and coiled tubing.

3. The well system of claim 1, wherein the detecting unit includes one or more gyroscopes operable to detect deviations of the at least one of the conveyance and the downhole tool from the predefined center of the casing.

4. The well system of claim 3, wherein the one or more gyroscopes determine real-time X and Y coordinates of the at least one of the conveyance and the downhole tool as the downhole tool is conveyed into the wellbore.

5. The well system of claim 4, wherein the one or more gyroscopes include:

one or more first gyroscopes arranged and configured to detect deviations of the at least one of the conveyance and the downhole tool in the X direction; and

one or more second gyroscopes arranged and configured to detect deviations of the at least one of the conveyance and the downhole tool in the Y direction.

6. The well system of claim 1, wherein the one or more propellers are selectively operated to individually re-center the at least one of the conveyance and the downhole tool toward the predefined center.

7. The well system of claim 1, wherein the one or more propellers comprise a plurality of propellers selectively operated simultaneously to cooperatively re-center the at least one of the conveyance and the downhole tool toward the predefined center.

8. The well system of claim 1, wherein the non-contact auto centralizer further includes a control unit in communication with the detecting unit and the re-centering unit, the control unit being operable to control operation of the non-contact auto centralizer.

9. The well system of claim 8, wherein the control unit is programmed to activate the one or more propellers to untwist the conveyance within the wellbore.

10. The well system of claim 8, wherein the control unit is programmed to:

determine real-time X and Y coordinates of the at least one of the conveyance and the downhole tool;

compare the real-time X and Y coordinates of the at least one of the conveyance and the downhole tool with reference X and Y coordinates of the casing; and

determine if the real-time X and Y coordinates deviate beyond a predetermined deviation threshold with respect to the reference X and Y coordinates.

11. The well system of claim 10, wherein the control unit is programmed to activate the one or more propellers to re-center the at least one of the conveyance and the downhole tool toward the predefined center upon determining that the real-time X and Y coordinates deviate beyond the predetermined deviation threshold.

12. The well system of claim 1, wherein the non-contact auto centralizer comprises a first non-contact auto centralizer attached to the conveyance at a first location, the well system further comprising a second non-contact auto centralizer attached to the conveyance at a second location axially offset from the first non-contact auto centralizer.

13. A method for centralizing a conveyance in a wellbore during a wellbore intervention operation, the method comprising:

introducing a downhole tool into a wellbore extending from a wellhead installation arranged at a surface location, the downhole tool being attached to the conveyance, and the wellbore being at least partially lined with casing;

introducing a non-contact auto centralizer attached to the conveyance simultaneously with the downhole tool, the non-contact auto centralizer including a detecting unit and a re-centering unit including one or more propellers;

detecting a deviation of at least one of the conveyance and the downhole tool from a predefined center of the casing with the detecting unit; and

operating the one or more propellers and thereby re-centering the at least one of the conveyance and the downhole tool toward the predefined center.

14. The method of claim 13, wherein the detecting unit includes one or more gyroscopes, and wherein detecting the deviation of the at least one of the conveyance and the downhole tool from the predefined center comprises detecting deviations of the at least one of the conveyance and the downhole tool from the predefined center with the one or more gyroscopes.

15. The method of claim 14, further comprising determining real-time X and Y coordinates of the at least one of the conveyance and the downhole tool with the one or more gyroscopes determine as the downhole tool is conveyed into the wellbore.

16. The method of claim 13, wherein the non-contact auto centralizer further includes a control unit in communication with the detecting unit and the re-centering unit, the method further comprising controlling operation of the non-contact auto centralizer with the control unit.

17. The method of claim 16, further comprising activating the one or more propellers with the control unit to untwist the conveyance within the wellbore.

18. The method of claim 16, wherein the control unit is programmed to:

19. The method of claim 19, wherein the control unit is programmed to activate the one or more propellers to re-center the at least one of the conveyance and the downhole tool toward the predefined center upon determining that the real-time X and Y coordinates deviate beyond the predetermined deviation threshold.