The present disclosure describes apparatus, systems, and methods for determining a location of a tool in a tubular.
Determining an orientation, speed, and position of a tool in a tubular is challenging. In the case of downhole tubulars in wellbores, wireline downhole tools typically use a wire length (for example, between a surface and the tool at depth) as reference for the tool's position. Spooling rate of the wireline is related to the tool's speed. As the cable length becomes longer, relating position and velocity of the tool to length and spooling of the wire becomes more difficult. Emerging as an alternative to wireline tools, untethered tools do not have any well-known method to estimate location and velocity. The same problem exists also for surface pipelines through which tools (for example, “pigs” are run). Pigs can be used to inspect and clean pipelines. Steel pipelines, however, block electromagnetic radiation, and thus, positioning technologies cannot be used.
In an example implementation, a measurement tool system includes a tool and a controller. The tool includes a housing configured to fit within and run into a magnetized tubular member, the housing defining an interior volume; a first magnetic field sensor positioned on or within the housing at a first location; and a second magnetic field sensor positioned on or within the housing at a second location apart from the first location by a separation distance. Each of the first and second magnetic field sensors is configured to detect a magnetic field amplitude value of a stationary magnetic field generated by the magnetized tubular member. The controller is configured to perform operations including identifying a first magnetic field amplitude distribution sensed by the first magnetic field sensor started at a first time instant; identifying a second magnetic field amplitude distribution sensed by the second magnetic field sensor started at a second time instant; determining a time difference between the first and second time instants based on the identified first and second magnetic field amplitudes; and determining a speed of the housing based on the separation distance and the time difference.
In an aspect combinable with the example implementation, at least one of the first or second magnetic field sensors includes a magnetoresistance or hall-effect sensor.
In another aspect combinable with any of the previous aspects, the magnetized tubular member includes a wellbore casing or a hydrocarbon system pipeline.
In another aspect combinable with any of the previous aspects, the controller is configured to perform operations further including determining, based on the speed of the housing, a location of the housing within the magnetized tubular member.
In another aspect combinable with any of the previous aspects, determining, based on the speed of the housing, a location of the housing within the magnetized tubular member includes determining a displacement of the housing by integrating the speed over the time difference; and determining the location based on the determined displacement and a known location of the housing at the first time instant.
In another aspect combinable with any of the previous aspects, the separation distance is based on a reference distance for a change to the magnetic field amplitude value of the stationary magnetic field at least above a noise level of the stationary magnetic field.
In another aspect combinable with any of the previous aspects, the separation distance is less than or equal to the reference distance.
In another aspect combinable with any of the previous aspects, the separation distance is greater than the reference distance.
In another aspect combinable with any of the previous aspects, determining the time difference between the first and second time instants based on the identified first and second magnetic field amplitudes includes (i) determining a time window for the first magnetic field sensor that begins at the first time instant, the time window including a plurality of first magnetic field amplitudes sensed by the first magnetic field sensor; (ii) determining a first time window for the second magnetic field sensor of the same duration as the time window for the first magnetic field sensor, the first time window including a plurality of second magnetic field amplitudes sensed by the second magnetic field sensor; (iii) determining an absolute value of each difference between corresponding first magnetic field amplitudes in the time window for the first magnetic field sensor and second magnetic field amplitudes in the first time window of the second magnetic field sensor; (iv) determining a sum of the absolute values to determine a metric of dissimilarity; (v) shifting the first time window for the second magnetic field sensor by a time shift to generate a next time window for the second magnetic field sensor; (vi) based on the shifting, iterating operations (iii)-(v) for a specified number of iterations to determine a plurality of metrics of dissimilarity; (vii) determining a minimum metric of dissimilarity of the plurality of metrics of dissimilarity; and (viii) identifying a time instant associated with the minimum metric of dissimilarity, the identified time instant including the second time instant.
In another aspect combinable with any of the previous aspects, the time window is based on an expected speed of the housing and the separation distance.
In another aspect combinable with any of the previous aspects, the controller is configured to perform operations further including processing the plurality of first magnetic field amplitudes sensed by the first magnetic field sensor in the time window between (i) and (iii); and processing the plurality of second magnetic field amplitudes sensed by the second magnetic field sensor in the first time window between (ii) and (iii).
In another aspect combinable with any of the previous aspects, the processing includes at least one of subtracting a mean value of the plurality of first magnetic field amplitudes from each of the plurality of first magnetic field amplitudes, and subtracting a mean value of the plurality of second magnetic field amplitudes from each of the plurality of second magnetic field amplitudes; or normalizing the plurality of first magnetic field amplitudes and the plurality of second magnetic field amplitudes.
In another example implementation, a method for operating a tool includes moving a tool in a magnetized tubular member that generates a stationary magnetic field. The tool includes a housing that defines an interior volume, a first magnetic field sensor positioned on or within the housing at a first location, and a second magnetic field sensor positioned on or within the housing at a second location apart from the first location by a separation distance. The method includes detecting a first magnetic field amplitude distribution sensed by the first magnetic field sensor started at a first time instant; detecting a second magnetic field amplitude distribution sensed by the second magnetic field sensor started at a second time instant; determining a time difference between the first and second time instants based on the identified first and second magnetic field amplitudes; and determining a speed of the tool moving in the magnetized tubular member based on the separation distance and the time difference.
In an aspect combinable with the example implementation, at least one of the first or second magnetic field sensors includes a magnetoresistance or hall-effect sensor.
In another aspect combinable with any of the previous aspects, the magnetized tubular member includes a wellbore casing or a hydrocarbon system pipeline.
Another aspect combinable with any of the previous aspects further includes determining, based on the speed of the tool, a location of the tool within the magnetized tubular member.
In another aspect combinable with any of the previous aspects, determining, based on the speed of the tool, a location of the tool within the magnetized tubular member includes determining a displacement of the tool by integrating the speed over the time difference; and determining the location based on the determined displacement and a known location of the tool at the first time instant.
In another aspect combinable with any of the previous aspects, the separation distance is based on a reference distance for a change to the magnetic field amplitude value of the stationary magnetic field at least above a noise level of the stationary magnetic field.
In another aspect combinable with any of the previous aspects, the separation distance is less than or equal to the reference distance.
In another aspect combinable with any of the previous aspects, the separation distance is greater than the reference distance.
In another aspect combinable with any of the previous aspects, determining the time difference between the first and second time instants based on the identified first and second magnetic field amplitudes includes (i) determining a time window for the first magnetic field sensor that begins at the first time instant, the time window including a plurality of first magnetic field amplitudes sensed by the first magnetic field sensor; (ii) determining a first time window for the second magnetic field sensor of the same duration as the time window for the first magnetic field sensor, the first time window including a plurality of second magnetic field amplitudes sensed by the second magnetic field sensor; (iii) determining an absolute value of each difference between corresponding first magnetic field amplitudes in the time window for the first magnetic field sensor and second magnetic field amplitudes in the first time window of the second magnetic field sensor; (iv) determining a sum of the absolute values to determine a metric of dissimilarity; (v) shifting the first time window for the second magnetic field sensor by a time shift to generate a next time window for the second magnetic field sensor; (vi) based on the shifting, iterating operations (iii)-(v) for a specified number of iterations to determine a plurality of metrics of dissimilarity; (vii) determining a minimum metric of dissimilarity of the plurality of metrics of dissimilarity; and (viii) identifying a time instant associated with the minimum metric of dissimilarity, the identified time instant including the second time instant.
In another aspect combinable with any of the previous aspects, the time window is based on an expected speed of the tool and the separation distance.
Another aspect combinable with any of the previous aspects further includes processing the plurality of first magnetic field amplitudes sensed by the first magnetic field sensor in the time window between (i) and (iii); and processing the plurality of second magnetic field amplitudes sensed by the second magnetic field sensor in the first time window between (ii) and (iii).
In another aspect combinable with any of the previous aspects, the processing includes at least one of subtracting a mean value of the plurality of first magnetic field amplitudes from each of the plurality of first magnetic field amplitudes, and subtracting a mean value of the plurality of second magnetic field amplitudes from each of the plurality of second magnetic field amplitudes; or normalizing the plurality of first magnetic field amplitudes and the plurality of second magnetic field amplitudes.
In another example implementation, a measurement tool includes a housing configured to fit within and run into a magnetized tubular member, where the housing defines an interior volume; a plurality of magnetic field sensors positioned on or within the housing, where each of the plurality of magnetic field sensors is configured to detect a magnetic field amplitude value of a stationary magnetic field generated by the magnetized tubular member, and each pair of adjacent magnetic field sensors is separated by a preset separation distance; and a controller positioned in the interior volume or on the housing. The controller is configured to perform operations including identifying a plurality of first magnetic field amplitudes sensed by the plurality of magnetic field sensors at a first time instant; identifying a plurality of second magnetic field amplitudes sensed by the plurality of magnetic field sensors at a second time instant subsequent to the first time instant; correlating the plurality of second magnetic field amplitudes sensed by the plurality of magnetic field sensors at the second time instant with the plurality of first magnetic field amplitudes sensed by the plurality of magnetic field sensors at the first time instant; and determining, based on the correlation, a distance between the housing at a first location in the magnetized tubular member at the first time instant and the housing at a second location in the magnetized tubular member at the second time instant.
In an aspect combinable with the example implementation, the controller is configured to perform operations further including determining a speed of the housing based on the distance and a difference between the second time instant and the first time instant.
In another aspect combinable with any of the previous aspects, the plurality of magnetic field sensors includes at least ten magnetic field sensors.
In another aspect combinable with any of the previous aspects, identifying the first plurality of magnetic field amplitudes sensed by the plurality of magnetic field sensors at the first time instant includes identifying one of the first plurality of magnetic field amplitudes that is sensed for each of the plurality of magnetic field sensors at the first time instant.
In another aspect combinable with any of the previous aspects, the magnetized tubular member includes a wellbore casing or a hydrocarbon system pipeline.
In another aspect combinable with any of the previous aspects, correlating the plurality of second magnetic field amplitudes sensed by the plurality of magnetic field sensors at the second time instant with the plurality of first magnetic field amplitudes sensed by the plurality of magnetic field sensors at the first time instant includes (i) determining, for each of the plurality of magnetic field sensors, an absolute value of a difference between the second magnetic field amplitude and the first magnetic field amplitude; and (ii) determining a sum of the absolute values to determine a metric of dissimilarity.
In another aspect combinable with any of the previous aspects, the controller is configured to perform operations further including (iii) identifying a plurality of next magnetic field amplitudes sensed by the plurality of magnetic field sensors at a next time instant subsequent to the second time instant; (iv) determining, for each of the plurality of magnetic field sensors, a next absolute value of a difference between the next magnetic field amplitude and the first magnetic field amplitude; and (v) determining a next sum of the next absolute values to determine a next metric of dissimilarity.
In another aspect combinable with any of the previous aspects, the controller is configured to perform operations further including (vi) iterating operations (iii)-(v) for a specified number of iterations to determine a plurality of metrics of dissimilarity; (vii) determining a minimum metric of dissimilarity of the plurality of metrics of dissimilarity; (viii) identifying a distance associated with the minimum metric of dissimilarity; and (ix) determining a new location of the housing at the next time instant based on the identified distance associated with the minimum metric of dissimilarity and previously known location at the first time instant
In another aspect combinable with any of the previous aspects, the controller is configured to perform operations further including determining speed of the housing based on the identified distance associated with the minimum metric of dissimilarity and a difference between the next time instant and the first time instant.
Implementations of a tool for operating in a tubular according to the present disclosure may include one or more of the following features. For example, a tool can accurately determine a speed and location (or displacement) of the tool within a tubular during movement within the tubular. As another example, a tool can utilize a stationary magnetic field produced or generated by the tubular (for example, a steel tubular) to determine speed and location (or displacement). As another example, a tool can determine a speed within a tubular that varies with time or distance traveled, as well as a constant or substantially constant speed within the tubular.
The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.
Although not illustrated in
As shown, the wellbore system 10 accesses a subterranean formation 40 and provides access to hydrocarbons located in such subterranean formation 40. In an example implementation of system 10, the system 10 may be used for a production operation in which the hydrocarbons may be produced from the subterranean formation 40 within the wellbore tubular 17 (for example, as a production tubing or casing). However, tubular 17 may represent any tubular member positioned in the wellbore 20 such as, for example, coiled tubing, any type of casing, a liner or lining, another downhole tool connected to a work string (in other words, multiple tubulars threaded together), or other form of tubular member.
A drilling assembly (not shown) may be used to form the wellbore 20 extending from the terranean surface 12 and through one or more geological formations in the Earth. One or more subterranean formations, such as subterranean zone 40, are located under the terranean surface 12. As will be explained in more detail below, one or more wellbore casings, such as a surface casing 30 and intermediate casing 35, may be installed in at least a portion of the wellbore 20. In some embodiments, a drilling assembly used to form the wellbore 20 may be deployed on a body of water rather than the terranean surface 12. For instance, in some embodiments, the terranean surface 12 may be an ocean, gulf, sea, or any other body of water under which hydrocarbon-bearing formations may be found. In short, reference to the terranean surface 12 includes both land and water surfaces and contemplates forming and developing one or more wellbore systems 10 from either or both locations.
In some embodiments of the wellbore system 10, the wellbore 20 may be cased with one or more casings. As illustrated, the wellbore 20 includes a conductor casing 25, which extends from the terranean surface 12 shortly into the Earth. A portion of the wellbore 20 enclosed by the conductor casing 25 may be a large diameter borehole. Additionally, in some embodiments, the wellbore 20 may be offset from vertical (for example, a slant wellbore). Even further, in some embodiments, the wellbore 20 may be a stepped wellbore, such that a portion is drilled vertically downward and then curved to a substantially horizontal wellbore portion. Additional substantially vertical and horizontal wellbore portions may be added according to, for example, the type of terranean surface 12, the depth of one or more target subterranean formations, the depth of one or more productive subterranean formations, or other criteria.
Downhole of the conductor casing 25 may be the surface casing 30. The surface casing 30 may enclose a slightly smaller borehole and protect the wellbore 20 from intrusion of, for example, freshwater aquifers located near the terranean surface 12. The wellbore 20 may than extend vertically downward. This portion of the wellbore 20 may be enclosed by the intermediate casing 35. Any of the illustrated casings, as well as other casings that may be present in the wellbore system 10, may include one or more casing collars 55 (as shown in
Tools according to the present disclosure, such as downhole tool 100 and pipeline tool 165, may include two or more magnetic field sensors that, as described in more detail herein, allow for the determination of a speed, displacement, or location (or a combination thereof) in the tubular in which they are located. As described herein, the two or more magnetic field sensors located in or on the downhole tool 100 and pipeline tool 165 can, independently, sense amplitude values of the static magnetic field while traveling through such tubulars. The sensed amplitude values can be used to determine a speed, displacement, or location (or a combination thereof) in the tubular in which the tools 100 and 165 are located. The use of two or more magnetic field sensors (for example, magnetometers such as magnetoresistance or hall effect-based sensors, or any other magnetic field sensor that can detect stationary magnetic fields) solves issues related to the accurate determination of speed, location, and displacement of tools in steel tubulars. For example, for a downhole tool, casing collar locators are widely used downhole sensors that detect joint locations between two neighboring pipes. Length of each pipe and their order in a wellbore is known and recorded in a well completion report. Based on the completion report, detected joints are counted and used as location reference for the downhole tools. However, casing collar locators do not provide information within a tubular. Therefore, the position of a tool within a tubular must rely on other sensors or be estimated.
Downhole wellbore tools may also use natural gamma counts to determine depth and thus location of a tool within a wellbore. Various rock layers produce gamma rays at varying intensities depending on the lithology. A gamma log can be mapped on a reference depth measurement and can be used as a depth reference for the upcoming operations (for example, logging). Typically, gamma ray tools can provide a vertical resolution of 12 inches, but require a large volume and power, which is not suitable for small and low power systems (such as untethered logging tools).
As another example, accelerometers and gyroscopes can be used to track changes in a motion of a tool in a tubular. However, as the output integral is calculated to find velocity, position, and rotation, error quickly accumulates and results in inaccurate measurements. Moreover, it is not possible to predict if a tool is stationary or moving at a constant speed based on the acceleration data. Regarding surface pipelines, the same issues exist as described for downhole tools. Further, as steel tubulars block electromagnetic radiation, positioning technologies cannot be used with pigs.
As noted, steel tubulars exhibit (or generate) a static magnetic field (for example, due to the manufacturing process of such tubulars). The static magnetic field can be sensed (by the two or more magnetic field sensors of a tool according to the present disclosure) and recorded. For example, turning to
As shown by curve 416, within a discrete portion of a downhole steel tubular (or surface steel pipeline), the sensed magnetic field amplitude varies and includes recognizable peaks and valleys. Such recognizable portions of the curve 416 may be identified as “features” or “windows” (that will be described in more detail later). For example,
The “feature size” refers to the length of the window (in distance or time) that makes it differentiable from adjacent portions of the signal curve. The feature sizes of the windows 426 in
As seen in the
Such a spectrum analysis can be applied over a distance (as described) or over a time. For example, in some aspects, the tool moving, for example, downhole in a wellbore steel tubular has a depth reference (for example, a logging tool or casing collar locator). In such cases, the spectrum analysis can be applied over a distance as described. But in examples in which the tool moving through the steel tubular has no depth reference, the spectrum analysis can be applied over time. For example, in a time spectrum analysis, magnetic field amplitude measurements are acquired (for example, by the two or more magnetic field sensors of the tool) with respect to time, where the scale of the time axis may depend on the tool speed. The spectrum analysis that is described with reference to
For instance,
In some aspects, the time spectrum analysis can yield different time window lengths for different tool speeds; however, in many tool operations, the tool speed may not significantly change during tool job. Thus, an average time window length can be acquired. Alternatively, if the tool speed is expected to change significantly, the spectrum analysis can be continuously done (for example, by a controller on board the tool) during the movement of the tool inside the steel tubular, and the window length can be dynamically adjusted (for example, during movement of the tool in the steel tubular). As an example, a new spectrum can be calculated from the data (magnetic field amplitude values) collected in the last, for example, 1 minute, and the frequency content can be analyzed to limit the window length based on such data.
The example implementation of the tool 200 in
As shown in
The example implementation of the tool 200 also includes a controller 999. In some aspects, the controller 999 is a microprocessor-based controller that includes, for example, one or more hardware processors and one or more tangible memory modules that store instructions for the processors to execute. By executing such instructions, the controller 999 can perform operations according to the present disclosure for the tool 200 (including the magnetic field sensors 204 and 206).
As shown,
The example implementation of the tool 250 in
As shown in
The example implementation of the tool 250 also includes a controller 999. In some aspects, the controller 999 is a microprocessor-based controller that includes, for example, one or more hardware processors and one or more tangible memory modules that store instructions for the processors to execute. By executing such instructions, the controller 999 can perform operations according to the present disclosure for the tool 250 (including the magnetic field sensors 254a-254j).
Just as with tool 200, the tool 250 may move through a tubular. At a time, t0, the magnetic field sensor 254a is at a location (for example, depth in the wellbore tubular 17) of z0, while the magnetic field sensor 254b is at a location of z0+Δz (the location of the magnetic field sensor 254a plus the separation distance 260), the magnetic field sensor 254c is at a location of z0+2Δz (the location of the magnetic field sensor 254a plus twice the separation distance 260), and so on. The tool 250 can move with a particular speed through the steel tubular. At a subsequent (to t0) time, t1, the magnetic field sensor 254a is at a location (for example, depth in the wellbore tubular 17) of z1, while the magnetic field sensor 254b is at a location of z1+Δz (the location of the magnetic field sensor 254a plus the separation distance 260), the magnetic field sensor 254c is at a location of z1+2Δz (the location of the magnetic field sensor 254a plus twice the separation distance 260), and so on. At both times, to and t1, and at time instants between such two times, the ten magnetic field sensors 254a-254j may be sensing magnetic field amplitudes generated by the stationary magnetic field of the wellbore tubular 17 (and, in some aspects, providing or exposing such sensed measurements relative to time to the controller 999).
Method 300 may continue at step 304, which includes detecting a first magnetic field amplitude distribution sensed by a first magnetic field sensor started at a first time instant at a particular location. For example, as the tool 200 is moving through the steel tubular, a first magnetic field sensor (for example, sensor 206 on tool 200) detects magnetic field amplitudes, including at a first time instant (for example, t0). In some aspects, a first magnetic field sensor of a tool can be the magnetic field sensor (of several sensors) that is positioned in the tool at a front (or downhole) end of the tool, i.e., toward a direction of movement of the tool. The first magnetic field sensor can detect magnetic field amplitudes continuously or periodically during movement of the tool through the steel tubular, with such magnitude values being recorded or identified by the controller 999.
Method 300 may continue at step 306, which includes detecting a second magnetic field amplitude distribution sensed by a second magnetic field sensor at the particular location (for example, the same location as the first sensor) and started at a second time instant. For example, as the tool 200 moves a distance that is equal to the length between the two sensors through the steel tubular, a second magnetic field sensor (for example, sensor 204 on tool 200) detects magnetic field amplitudes, including at a second time instant subsequent to the first time instant (for example, t1). In some aspects, a second magnetic field sensor of a tool can be the magnetic field sensor (of several sensors) that is positioned in the tool at a rear (or uphole) end of the tool, i.e., away a direction of movement of the tool. The second magnetic field sensor can also be, in the case of tool 250 with ten sensors, adjacent the first magnetic field sensor (for example, with 254j being the first magnetic field sensor and 254i being the second magnetic field sensor). The second magnetic field sensor can detect magnetic field amplitudes continuously or periodically during movement of the tool through the steel tubular, with such magnitude values also being recorded or identified by the controller 999.
Method 300 may continue at step 308, which includes determining a time difference between the first and second time instants based on the identified first and second magnetic field amplitude distributions (or, for example, magnetic field patterns that correspond to the same location inside a magnetized tubular member). For example, in some aspects, the controller 999 may correlate the identified first and second magnetic field amplitudes, that constitutes a feature, to determine, for example, a minimum (or no) difference between the second magnetic field amplitudes (taken starting at time, t1) and the first magnetic field amplitudes (taken starting at t0). Such a determined minimal difference can indicate, for example, that the second magnetic field sensor passed a particular location within the steel tubular at the time, t1, after the first magnetic field sensor passed the same particular location at the time, to (based on a measured magnetic field amplitude values at that particular location of the steel tubular). After determining such a minimal difference (or zero difference), the second time instant (t1) can be determined by the controller 999 as the time instant when such minimal difference occurred. Thereafter, the controller 999 can determine the time difference between t1 and to.
An example implementation of step 308 and the correlation between the identified first and second magnetic field amplitudes is shown in
The sub-process of
In some aspects, a time span can be defined as a duration of time where at least a magnetic field feature, or pattern, can be identified and it can be longer than the length of a window. For example, in
The sub-process of
The sub-process of
In some aspects, normalizing (or normalization) includes dividing each measurement point in the window with the absolute maximum value within that window, so that the absolute maximum value within the window becomes 1, and absolute value of every other element becomes smaller than or equal to 1. In other words, in some aspects, all values are scaled by a constant to make them in the interval of [−1, 1]. In some aspects, the processing, such mean subtraction and normalizing can help to remove differences between two different sensors. For instance, a magnetic field at a location can be measured slightly differently by two different sensors and this can be due to slight difference in the placement of the sensors, calibration of the sensors, or any other inherent property of a particular sensor such as different magnetic field bias or sensitivity because of the fabrication tolerances.
The sub-process of
The sub-process of
The sub-process of
If the determination in step 332 is no, then the sub-process of
If the determination in step 332 is yes, then the sub-process of
As noted, the x-axis 602 is in time shifts, which can be a time difference between the start times of the first and second windows, namely how much the second window is shifted in time at a dissimilarity calculation step. Thus, as illustrated, the time metric of the x-axis in
The sub-process of
Method 300 may continue at step 310, which includes determining a speed of the tool moving in the magnetized tubular member based on a known separation distance and the identified time difference. For example, once the time difference in step 308 is determined, speed of the tool can be determined based on a ratio of separation distance (for example, between the first and second magnetic field sensors 206 and 204, respectively) and the determined time difference. For example, for the determined time difference, Δt, an average speed can be found as vav=Δz/Δt.
Furthermore, a universal time stamp can be assigned to the calculated average speed (for example provided by a time that is kept by the controller 999 of the tool from the beginning of the job or a time that is synchronized to another reference time). For example, it can be the mean value of the times t1 and t0.
Method 300 may continue at step 312, which includes determining, based on the speed of the tool, a location of the tool within the magnetized tubular member. For example, based on a previous speed that has been determined, or a known instant in which the tool began to move through the steel tubular, a location or relative location of the tool in the steel tubular may be determined. For example, traveled distance since the last known reference point can be found by multiplying the calculated average speed by the elapsed time since when the tool was at the last known reference point until the time stamp of the calculated speed.
Method 300 may be recursively repeated to provide a continuous update of tool's speed and location during the job.
In some aspects, one or more steps of method 300 (or the sub-process shown in
The scanning action of an array of magnetic field sensors results in scaling of the magnetic field amplitude values in time as a function of speed. As shown in
Additionally, in some aspects, for a tool with an array of magnetic field sensors (such as tool 250), position, or displacement, of the tool can be determined directly without relying on the time reference. For a tool with two magnetic field sensors, displacement can be calculated first by determining the speed, and then by integrating the speed along time. Since the error in the speed measurement accumulates, after some time, the position measurement can be off when determining speed with a two-sensor tool. Directly measuring the position can prevent this error.
Considerations for a tool with an array of magnetic field sensors (such as tool 250) can be a number of the sensors and separation distance between the sensors. The separation distance between magnetic field sensors, in some aspects, can be selected smaller than the feature size in order to resolve them. For example, employing the Nyquist theorem, twice the sampling rate of the highest frequency content that should be resolved may be required. For example, as described, there may be features up to 1 ft−1 frequency. Therefore, in an array, magnetic field sensors can be placed with a rate of 2 ft−1, which corresponds to a minimum of 0.5 ft. separation distance. In order to increase the accuracy of the amplitude measurement and displacement detection, the separation can be less (e.g., 0.1 ft.). The total length of the magnetic field sensor array with the determined separation distance can cover a distance that is enough to capture at least one feature at a time (e.g., 1-2 ft.). The discrete data then can be interpolated, for example using a cubic spline function before applying method 300.
In another example implementation, similar to the downhole tool shown in
Method 750 may continue at step 754, which includes detecting a first spatial magnetic field amplitude distribution sensed by an array of magnetic field sensors at a first time instant. For example, as described with reference to
Method 750 may continue at step 756, which includes detecting a second spatial magnetic field amplitude distribution sensed by the array of magnetic field sensors at a second time instant. For example, as described with reference to
Method 750 may continue at step 758, which includes determining a displacement of the tool moving in the magnetized tubular member based on a separation distance. For example, a minimum dissimilarity metric is found when the window is shifted for a particular distance. This result can indicate the amount of displacement directly that happened between the times to and t1.
Step 758 can be implemented by sub-process 770, which is shown in
The sub-process of
The sub-process of
The sub-process of
The sub-process of
If the determination in step 782 is no, then the sub-process of
If the determination in step 782 is yes, then the sub-process of
The sub-process of
Method 750 may continue at step 760, which includes determining a location of the tool moving in the magnetized tubular member based on the displacement of the tool. For example, the location of the tool can be tracked by adding the displacements together with respect to a previously known reference depth or length such as the surface, or a casing joint that is detected using a casing collar locator. Also, an average speed can be calculated by dividing this distance by the absolute value of the difference between t1 and to (however, speed calculation is not necessary to find the displacement and location.)
Method 750 may be recursively repeated to provide a continuous update of tool's location during the job.
The controller 800 includes a processor 810, a memory 820, a storage device 830, and an input/output device 840. Each of the components 810, 820, 830, and 840 are interconnected using a system bus 850. The processor 810 is capable of processing instructions for execution within the controller 800. The processor may be designed using any of a number of architectures. For example, the processor 810 may be a CISC (Complex Instruction Set Computers) processor, a RISC (Reduced Instruction Set Computer) processor, or a MISC (Minimal Instruction Set Computer) processor.
In one implementation, the processor 810 is a single-threaded processor. In another implementation, the processor 810 is a multi-threaded processor. The processor 810 is capable of processing instructions stored in the memory 820 or on the storage device 830 to display graphical information for a user interface on the input/output device 840.
The memory 820 stores information within the controller 800. In one implementation, the memory 820 is a computer-readable medium. In one implementation, the memory 820 is a volatile memory unit. In another implementation, the memory 820 is a non-volatile memory unit.
The storage device 830 is capable of providing mass storage for the controller 800. In one implementation, the storage device 830 is a computer-readable medium. In various different implementations, the storage device 830 may be a floppy disk device, a hard disk device, an optical disk device, a tape device, flash memory, a solid state device (SSD), or a combination thereof.
The input/output device 840 provides input/output operations for the controller 800. In one implementation, the input/output device 840 includes a keyboard and/or pointing device. In another implementation, the input/output device 840 includes a display unit for displaying graphical user interfaces.
The features described can be implemented in digital electronic circuitry, or in computer hardware, firmware, software, or in combinations of them. The apparatus can be implemented in a computer program product tangibly embodied in an information carrier, for example, in a machine-readable storage device for execution by a programmable processor; and method steps can be performed by a programmable processor executing a program of instructions to perform functions of the described implementations by operating on input data and generating output. The described features can be implemented advantageously in one or more computer programs that are executable on a programmable system including at least one programmable processor coupled to receive data and instructions from, and to transmit data and instructions to, a data storage system, at least one input device, and at least one output device. A computer program is a set of instructions that can be used, directly or indirectly, in a computer to perform a certain activity or bring about a certain result. A computer program can be written in any form of programming language, including compiled or interpreted languages, and it can be deployed in any form, including as a stand-alone program or as a module, component, subroutine, or other unit suitable for use in a computing environment.
Suitable processors for the execution of a program of instructions include, by way of example, both general and special purpose microprocessors, and the sole processor or one of multiple processors of any kind of computer. Generally, a processor will receive instructions and data from a read-only memory or a random access memory or both. The essential elements of a computer are a processor for executing instructions and one or more memories for storing instructions and data. Generally, a computer will also include, or be operatively coupled to communicate with, one or more mass storage devices for storing data files; such devices include magnetic disks, such as internal hard disks and removable disks; magneto-optical disks; and optical disks. Storage devices suitable for tangibly embodying computer program instructions and data include all forms of non-volatile memory, including by way of example semiconductor memory devices, such as EPROM, EEPROM, solid state drives (SSDs), and flash memory devices; magnetic disks such as internal hard disks and removable disks; magneto-optical disks; and CD-ROM and DVD-ROM disks. The processor and the memory can be supplemented by, or incorporated in, ASICs (application-specific integrated circuits).
To provide for interaction with a user, the features can be implemented on a computer having a display device such as a CRT (cathode ray tube) or LCD (liquid crystal display) or LED (light-emitting diode) monitor for displaying information to the user and a keyboard and a pointing device such as a mouse or a trackball by which the user can provide input to the computer. Additionally, such activities can be implemented via touchscreen flat-panel displays and other appropriate mechanisms.
The features can be implemented in a control system that includes a back-end component, such as a data server, or that includes a middleware component, such as an application server or an Internet server, or that includes a front-end component, such as a client computer having a graphical user interface or an Internet browser, or any combination of them. The components of the system can be connected by any form or medium of digital data communication such as a communication network. Examples of communication networks include a local area network (“LAN”), a wide area network (“WAN”), peer-to-peer networks (having ad-hoc or static members), grid computing infrastructures, and the Internet.
While this specification contains many specific implementation details, these should not be construed as limitations on the scope of any inventions or of what may be claimed, but rather as descriptions of features specific to particular implementations of particular inventions. Certain features that are described in this specification in the context of separate implementations can also be implemented in combination in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations separately or in any suitable subcombination. Moreover, although features may be described above as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can in some cases be excised from the combination, and the claimed combination may be directed to a subcombination or variation of a subcombination.
Similarly, while operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results. In certain circumstances, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the implementations described above should not be understood as requiring such separation in all implementations, and it should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software products.
A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, example operations, methods, or processes described herein may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in different successions than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims.