Patent Application
20210254453
This disclosure relates generally to measuring downhole tool conveyance and retrieval. More specifically, this disclosure relates to techniques for stand break detection and logging while tripping (LWT).
This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.
Producing hydrocarbons from a wellbore drilled into a geological formation is a remarkably complex endeavor. During drilling operations, evaluations of the composition within the geological formation may be performed for various purposes, such as to locate hydrocarbon-producing formations and manage the production of hydrocarbons from these formations. To determine the location of hydrocarbon producing formations, as well as various geological formations, downhole tools are conveyed by various means, such as coiled tubing, drill pipe, casing or other conveyers. One or more drill pipes may be removed from the string via tripping out of the pipes.
At least in some instances, tripping out of the pipes may be used to inform certain oil and gas operations. For example, the downhole tool may include a well logging tool that measures physical properties of the geological formation at different positions of the wellbore (e.g., along a vertical and/or horizontal portion) while the drill string is being tripped out the wellbore. This process is referred to as logging while tripping (LWT). At least in some instances during LWT, the well logging tool may be a wireless well logging tool and, as such, may not be in communication with computing systems at the surface. The data obtained by such well logging tools includes measurements as a function of time. The data may be later converted to measurements as a function of position within the wellbore based on a time period that corresponds to when one or more length of pipes were raised out of the wellbore.
A summary of certain embodiments disclosed herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure. Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.
One embodiment of the present disclosure relates to a system for stand break detection. The system includes a data processing system having a processor configured to execute instructions stored in a memory of the data processing system to perform actions. The actions include receiving measured movement data from at least one sensor associated with a component of a rig during a tripping process of a drill string having a plurality of drill pipes. The actions also include identifying a stand break associated with the drill pipes of the plurality of drill pipes based at least in part on the measured movement data.
Another embodiment of the present disclosure relates a method. The method includes receiving, via the processor, a first set of sensor data obtained by a first sensor disposed on a first component of a rig, wherein the first set of sensor data comprises movement data indicative of movement of the component of the rig and time data. The method also includes receiving, via the processor, a second set of sensor data obtained by a second sensor disposed on a second component of the rig, wherein the second set of sensor data comprises movement data indicative of movement of the component of the rig and the time data. Further, the method includes identifying, via the processor, a stand break based at least in part on a first portion of the first set of sensor data and a second portion of the second set of sensor data comprising movement data below a movement threshold. Further still, the method includes identifying, via the processor, a length of a drill pipe associated with at least the first portion of the first set of sensor data, the second portion of the second set of sensor data, or both, based at least in part on the stand break
Another embodiment of the present disclosure relates to an article of manufacturer comprising instructions that, when executed by at least one processor, cause the at least one processor to receive a first set of data obtained by a first sensor disposed on a first component of a rig during a tripping process, wherein the first set of data comprises data indicative of a traveling block position; receive a second set of data obtained by a second sensor disposed a second component of the rig during the tripping process, wherein the second set of data comprises data indicative of a position of a drill bit of the rig; determine stand length based at least in part on the second set of data; and determine a stand break based at least in part on a comparison between the first set of data and the determined stand length.
Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure. Further features may also be incorporated in these various aspects as well. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. The brief summary presented above is intended to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.
Various aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which:
One or more specific embodiments of the present disclosure will be described below. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would still be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.
In the present context, the term “about” or “approximately” is intended to mean that the values indicated are not exact and the actual value may vary from those indicated in a manner that does not materially alter the operation concerned. For example, the term “about” or “approximately” as used herein is intended to convey a suitable value that is within a particular tolerance (e.g., ±10%, ±5%, ±1%, ±0.5%), as would be understood by one skilled in the art.
As referred to herein, “to trip” or “tripping” pipe refers to the process of pulling a drill string out of a wellbore. As referred to herein, a “drill string” is a combination of drill pipes. As referred to herein, a “stand” is two or more joints of drill pipes or drill collars that may be physically coupled (e.g., via a threaded connection) while a pipe is tripped. As referred to herein, a “stand break” is the removal of a drill pipe from at least one of the joined of the drill pipes.
Tripping drill pipes generally includes a step of raising one or more drill pipes out of the wellbore (e.g., using machinery) and an additional step of removing the one or more drill pipes from the drill string (e.g., a stand break). As mentioned above, certain operations that occur during tripping of drill pipes of the downhole tool system, such as during logging-while-tripping (LWT) operations, may have data that is based on determining times associated with, or between, the step of raising one or more drill pipes and the step of removing the one or more drill pipes from the drill string. For example, the well logging tool may be a wireless well logging tool and, as such, may not be in communication with any computing devices on the surface (e.g., via a wireline) while the wireless downhole tool is in the subsurface including the wellbore. Instead, the data associated with the measured physical properties of the surrounding geological formation is retrieved after the wireless downhole tool is removed from the wellbore at the surface. It should be noted that the data obtained by the wireless downhole tool may include one or more measurements as a function of time instead of a position (e.g., depth and/or horizontal position) because the well logging tool may not be in communication with any other computing devices at the surface. It should be appreciated that converting the one or more measurements as a function of time to one or more measurements as a function of position may better inform certain oil and gas operations, such as where to drill.
It may be difficult to convert the one or measurements as a function of time to one or more measurements as a function of position within in wellbore. In particular, it may be difficult to identify a time period during tripping associated with the raising of the one or more drill pipes out of the wellbore and the stand break, when the one or more drill pipes are removed from the drill string, as various processes occur during tripping out that may interrupt pulling out of the drill string. For example, operators and/or machines may be placing the one or more drill pipes to be removed from the drill string “in-slips”. As discussed herein, “in-slips” generally refers to when the drill pipe(s) is coupled to a traveling block and raised a length approximately equal to the length of the drill pipe(s) (e.g., as discussed in further detail with regards to
In LWT operations, the one or more measurements as a function of time may be converted into one or more measurements as a function of depth based on the time at which one or more drill pipes are tripped. That is, LWT operations, as one or more drill pipes are raised out of a wellbore and/or removed from the drill string (e.g., a stand break occurrence), the well logging tool moves a distance along the wellbore (e.g., horizontally and/or vertically) within the subsurface that is proportional to the length of the one or more drill pipes that are raised out of the wellbore. Likewise, the time period corresponding to when the one or more pipes were raised out of the wellbore during tripping of the pipes. As such, the one or more measurements as a function of time may be converted into one or more measurements as a function of position (e.g., depth) based on the time period when the one or more drill pipes are pulled out of the wellbore and/or removed from the drill string. However, tripping pipe is a complex and multi-step process, which makes converting the one or more measurements as a function of time to one or more measurements as a function of position difficult. While the above-disclosure generally relates to LWT, it should be noted that the techniques of the present disclosure generally relate to operations associated with tripping pipes.
Accordingly, the present disclosure relates to stand break detection, which may determine when one or more drill pipes are removed from the drill string. In some embodiments, the techniques may include determining a length of the one or more drill pipes that are removed and/or converting one or more measurements as function of time (e.g., obtained by a well logging tool being removed from a wellbore by the tripping out system). For example, a processor may receive sensor data from at least one sensor (e.g., 1 sensor, 2 sensors, or more) as a function of time obtained via one or more components of the tripping out system and determines characteristic features of the sensor data that are indicative of the one or more drill pipes being removed from the drill string. In some embodiments, the sensor data may be processed data from an electronic drilling recorder (EDR), which may provide an estimated measurement of a drill bit depth. The data may be processed by any suitable processing formats, such as Wellsite information Transfer Specification (WITS). In some embodiments, the techniques include correlating a detected stand break to a length of one or more drill pipes that were removed from the drill string. At least in some instances, and as discussed in more detail with regard to
With the foregoing in mind,
Formation fluid or mud 32 (e.g., oil base mud (OBM) or water-based mud (WBM)) is stored in a pit 34 formed at the well site. A pump 36 delivers the formation fluid 52 to the interior of the drill string 16 via a port in the swivel 30, inducing the drilling mud 32 to flow downwardly through the drill string 16 as indicated by a directional arrow 38. The formation fluid exits the drill string 16 via ports in the drill bit 18, and then circulates upwardly through the region between the outside of the drill string 16 and the wall of the wellbore 14, called the annulus, as indicated by directional arrows 40. The drilling mud 32 lubricates the drill bit 18 and carries formation cuttings up to the surface as it is returned to the pit 34 for recirculation.
The downhole acquisition tool 12, sometimes referred to as a bottom hole assembly (“BHA”), may be positioned near the drill bit 18 and includes various components with capabilities, such as measuring, processing, and storing information, as well as communicating with the surface. A telemetry device (not shown) also may be provided for communicating with a surface unit (not shown). As should be noted, the downhole acquisition tool 12 may be conveyed on wired drill pipe, a combination of wired drill pipe and wireline, or other suitable types of conveyance.
In the illustrated embodiment of
The memory 48 of the well logging tool 42 may store the measurements obtained by the well logging tool subsystem 46 as well as control software, look up tables, configuration data, etc. The memory 48 may include a volatile memory, such as random access memory (RAM), and/or a nonvolatile memory, such as read-only memory (ROM). The memory 48 may store a variety of information and may be used for various purposes, such as the one or more measurements indicative. For example, the memory 48 may store processor-executable instructions including firmware or software for the processor 50 to execute. In some examples, the memory 48 is a tangible, non-transitory, machine-readable-medium that may store machine-readable instructions for the processor 50 to execute. The memory 48 may include ROM, flash memory, a hard drive, or any other suitable optical, magnetic, or solid-state storage medium, or a combination thereof. The memory 48 may store data, instructions, and any other suitable data. In some embodiments, the memory 48 may be included within the well logging tool subsystem 46.
The data obtained by the well logging tool 42 (e.g., well logging tool subsystem 46) and stored in the memory 48 may be retrieved and accessed by a data processing system 76 after the well logging tool 42 is retrieved from the wellbore 14. The data processing system 76 may include a processor 78, memory 80, storage 82, and/or display 84. The memory 80 may include one or more tangible, non-transitory, machine readable media collectively storing one or more sets of instructions for operating the downhole acquisition tool 12, determining formation characteristics (e.g., geometry, connectivity, minimum horizontal stress, etc.) calculating and estimating fluid properties of a reservoir fluid within the formation 20, modeling the fluid behaviors using, e.g., equation of state models (EOS). The memory 80 may store reservoir modeling systems (e.g., geological process models, petroleum systems models, reservoir dynamics models, etc.), mixing rules and models associated with compositional characteristics of the formation 20, equation of state (EOS) models for equilibrium and dynamic fluid behaviors (e.g., biodegradation, gas/condensate charge into oil, CO2 charge into oil, fault block migration/subsidence, convective currents, among others), and any other information that may be used to determine geological and fluid characteristics of the formation 20.
To process the data obtained by the well logging tool 42, the processor 78 may execute instructions stored in the memory 80 and/or storage 82. For example, the instructions may cause the processor to compare the data (e.g., from the logging while drilling and/or downhole analysis) with known reservoir properties estimated using the reservoir modeling systems, use the data as inputs for the reservoir modeling systems, and identify geological and reservoir fluid parameters that may be used for exploration and production of the reservoir. As such, the memory 80 and/or storage 82 of the data processing system 76 may be any suitable article of manufacture that can store the instructions. By way of example, the memory 80 and/or the storage 82 may be ROM memory, random-access memory (RAM), flash memory, an optical storage medium, or a hard disk drive. The display 84 may be any suitable electronic display that can display information (e.g., logs, tables, cross-plots, reservoir maps, etc.) relating to properties of the well/reservoir as measured by the downhole acquisition tool 12.
As mentioned above, the well logging tool 42 may be deployed within the wellbore 14 to obtain one or more measurements as a function of time indicative of physical properties of the formation 20. To illustrate the deployment of the well logging tool 42,
In
As shown in the illustrated example, the well logging tool 42 is deployed (e.g., removed from the drill string 16). That is, the well logging tool 42 is no longer within one or more drill pipes 44 of the drill string 16 and, instead, the well logging tool 42, or at least a portion of the well logging tool 42, is extending into the wellbore 14 and coupled to the drill bit 18 of the downhole acquisition tool 12. It should be noted that the well logging tool 42 may be checked for functionality while the well logging tool 42 is still attached to the cable 92 and/or still within the drill casing 16 via communication with the data processing system 76. In any case, the well logging tool 42 may be activated to begin collecting measurements as a function of time and be released from the cable 92.
To better illustrate how the techniques of the present disclosure may facilitate determination of a stand break (e.g., the time period when one or more drill pipes 44 were removed from the drill string 16),
As also shown in the illustrated embodiment, the rig 10 includes one or more sensors 108. In general, the one or more sensors 108 measure motion of the components of the rig 10 (e.g., the traveling block 100) and/or a position of the drill bit (e.g., drill bit 18 as shown in
In operation, the sensors 108 may obtain a measurement indicative of motion of the traveling block 100 and/or a value of the longitudinal distance 114 traveled by the traveling block 100. As discussed in further detail with regard to
Further, as the sensors 108 may obtain measurements indicative of the drill pipe 44a being removed from the drill string 16, the sensors 108 may also obtain measurement indicative of the traveling block 100 returning to an initial position (e.g., a minimum block position), as generally discussed with regards to
The data processing system 76, or any suitable processing system used during LWT operations, may use data stored in a drill pipe identification table to determine when one or more drills pipes 44 were removed from a drill string.
The illustrated embodiment of the drill pipe identification table 110 includes records 118 (e.g., rows) and fields 120 (e.g., columns) that display information associated with one or more drill pipes 44 of the drill string 16, such as a stand identification number 122, a pipe length 124, a tally depth 126, a bit depth 128, an offset 130, and a drift 132. In general, the stand identification number 122 indicates which stand corresponds to the drill pipes represented in the pipe length 124. The tally depth 126 includes reference data indicative of the depth of a drill pipe represented in the pipe length 124 relative to the first drill pipe. The bit depth 128 includes measurements received from the sensor(s) 108, The offset 130 and drift 132 represents an error between the bit depth 128 and the pipe length 124 and the tally depth 126. It should be noted that the information displayed in the drill pipe identification table 110 not meant to be limiting (e.g., some of the fields 120 may be removed and other fields may be added).
In operation, the data processing system 76 may generally access (e.g., retrieve data from and/or provide data to) the table to determine whether a stand break has occurred. For example, and as discussed in more detail with regard to
At least in some instances, the data processing system 76 may compare length information associated with the at least one drill pipe that is stored in the drill pipe identification table 110 to a length measured by the sensor 108 (e.g., an electronic data recorder (EDR) that may estimate a bit position, a sensor that receives measurements associated with a distance traveled by the traveling block 100). For example, the data processing system 76 may compare a received bit depth from the EDR that corresponds to a potential stand break and compare the received bit depth to a reference bit depth, such as a previously received bit depth that was determined to correspond to a stand break, which may be stored in the bit depth 128 field. The data processing system 76 may calculate a difference between the received bit depth and the reference bit depth and determined whether the difference corresponds to a length of one or more pipes. For example, as shown in the illustrated embodiment, a difference between two subsequent bit depths 128 is approximately equal to the sum of pipe lengths 124 in a corresponding stand identification number 122. In this way, and as discussed in more detail with regards to
Additionally or alternatively, the sensor 108 may be a tension meter measure a weight of components that are suspended from the hook 28. For example, the sensor 108 may be mounted on the drill line above a deadline anchor. For illustrative purposes,
With the foregoing in mind,
In the illustrate embodiment, the line plotted in the graph 140 generally includes regions where the slope of the estimated drill depth versus time is non-zero (e.g., regions 147 and 148) and regions where the slope of the estimated drill depth versus time is approximately zero (e.g., as regions 149 and 150). When the slope of the line in graph 140 may indicate that the drill bit 18 is moving when the slope is greater than zero (e.g., above a movement threshold), or the slope of the line in graph 140 may indicate that the drill bit 18 is stationary when the slope is approximately equal to zero.
The graph 142 shows an estimated position of the traveling block 100, which may be measured by one or more of the sensors 108 discussed herein. The line depicted in the graph 142 generally oscillates between a minimum position and a maximum position, which may be indicative of the traveling block 100 traveling along the distance 114, as discussed above with regards to
With the foregoing in mind,
Generally, the process 160 includes receiving sensor data from at least one sensor disposed on a rig 10 (process block 162), identifying a portion of the sensor data indicative of a stand break (process block 164), and generating a stand break output (process block 166).
In block 162, the data processing system 76 (e.g., processor 78) may receive sensor data from the sensors 108 that are disposed on or near the traveling block 100, the draw works 106, or any other component of the rig 10 that moves in conjunction with the one or more drill pipes 44 being raised out of the wellbore 14. In some embodiments, such as when the processor 78 and/or an operator determines that sensor data from at least one sensor has a signal-to-noise ratio (SNR) is below a predetermined SNR threshold or the sensor data from the at least one sensor includes artifacts that may make it difficult to process the sensor data, the data may be smoothed by suitable methods as understood by one of ordinary skill in the art.
The process 160 also includes identifying a portion of the sensor data obtained by the at least one sensor 108 that is indicative of a stand break based at least in part on the sensor data (process block 164). For example, the processor 78 may determine the portion of the sensor data is indicative of a stand break when the sensor data 108 (e.g., the drill depth data depicted in graph 140) does not change after a threshold amount of time. Referring briefly to
Additionally, the process 160 includes generating a stand break output based at least in part on the identified portion (process block 166). For example, the stand break output may be an alert that indicates a number of drill pipes 44 have been removed from the drill string (e.g., indicative that one or more drill pipes 44 have been removed and/or indicative of the number that have been removed. As a further non-limiting example, the stand break output may include data to be provided to the drill pipe identification able 110. In some embodiments, the stand break out may be a portion of data that corresponds to a length of pipes being raised out the wellbore e.g., within region 157). As a further non-limiting example, the stand break output may include a correction to a pipe tally. In this way, LWT operations nay be improved by reducing the amount of input provided by an operator during the operations, which may reduce costs associated with LWT operations.
With the foregoing in mind,
Generally, the process 170 includes receiving one or more measurements as a function of time from a well logging tool 42 retrieved from a wellbore 14 during LWT operations (process block 172). In particular, and as discussed herein, the well logging tool 42 may be wireless such that the well logging tool 42 may not be able to communicate with computing devices at the surface during tripping out. Instead, the one or more measurements as a function of time may be stored in the memory 48 of the well logging tool 42, retrieved at the surface (e.g., via an operator), and subsequently processed using the steps discussed below.
The process 170 also includes identifying at least one stand break during the LWT operations (process block 174). For example, the stand break may be identified based on sensor data received by the sensors 108, as discussed above. In some embodiments, the identified stand break may include the stand break output from process 160. That is, the processor 78 may receive a stand break output that correlates a time period during the LWT operations with a length of one or more drill pipes that were removed from the drill string 16. Further, the process 170 includes converting the one or more measurements as a function of time to one or more measurements as a function of position within the wellbore 14 based at least in part on the identified stand break (process block 176). For example, the processor 78 may convert at least a portion of the one or measurements as a function of time associated with a time period that at least partially overlaps with the time period where one or more drill pipes 44 were removed from the drill string to one or more measurements as a function of position within the wellbore 14 using the length of the one or more drill pipes 44 that were removed. As generally discussed herein, it should be noted that process block 172 may occur after process block 174.
To further illustrate an embodiment of the techniques of the present disclosure,
The process 180 generally includes receiving a first set of sensor data, such as bit depth data 182. Then, in decision block 184, the processor 78 may determine whether the bit depth data 182 is locked (e.g., stationary) for a time period longer than a threshold time (e.g., 5, 10, 20, 30, 60, 120 seconds, etc.). It should be noted that this may indicate that a drill pipe 44 is “in-slips,” or held in place by suitable gripping tools while one or more operators and/or machines remove the drill pipe 44 from the drill string 16. For example, as discussed above with regards to
After the processor 78 determines that the data included in the bit depth data 182 (e.g., regions 147 and/or 148) is indicative of the drill bit 18 being “in-slips” and/or remaining in a fixed position for a time period longer than the threshold time, the processor 78 may determine whether the bit depth data 182 has been unlocked above and/or below a threshold time and/or threshold distance (decision block 186), which may indicate whether the drill pipe(s) 44 being removed from the wellbore 14 are “out-of-slips.” Referring to
If the processor 78 determines that the bit depth data 182 has been unlocked above a threshold time and/or threshold distance, the processor 78 may determine a stand length based on the bit depth data 182 (process block 188). In some embodiments, the processor 78 may calculate the stand length based on a difference between a reference bit depth (e.g., previous “in-slips” bit depth) and the current bit depth (e.g., current “in-slips” bit depth). For example, the processor 78 may determine the current bit depth based on the value of the bit depth at region 150, and the processor 78 may determine the reference bit depth based on the value of the bit depth at region 149. In some embodiments, determining the reference bit depth may include the processor 74 accessing a record 118 in the drill pipe identification table 110 that includes the reference depth. Then, the processor 78 may determine the stand length based on the difference between the current bit depth and the reference bit depth.
In some embodiments, after determining the stand length, the processor 78 may determine whether the stand length (e.g., based on the current bit depth and the reference bit depth) is valid. For example, the processor may compare the stand length to a length of one or more drill pipes 44 to determine whether the stand length corresponds to a length of one drill pipe 44 or a length of multiple drill pipe 44 to confirm whether the determined stand length is valid. As such, it should be noted that this step may prevent incorrect determinations of stand lengths (e.g., false positives). In some embodiments, the lengths of the one or more drill pipes 44 may correspond to drill pipes that are expected to be below and/or above the current bit depth. Alternatively, the lengths of the one or more drill pipes may be a suitable reference length (e.g., an average pipe length 124). For example, turning briefly to the drill pipe identification table 110 of
In block 190, the processor 78 may determine the block position span (BPOS) based on the second set of data in response to determining that the stand length is valid. For example, the processor 78 may determine a block position span 192 (e.g., a value of distance) based on the change in block position over the region 157. To further confirm the validity of a stand break associated with the determined stand length, the processor 78, in decision block 194, may compare the block position span 192 to the stand length determined in block 188 to determine whether the block position span 192 corresponds to a possible stand length of one or more drill pipes 44. If the BPOS span is greater than the stand length, then the processor 78 may determine that a stand break did not occur, and thus, move on to the next data point of bit depth data 182.
If the processor 78 determines that the block position span 192 corresponds to a possible stand length of one or more drill pipes 44, the processor 78, decision block 196, may then determine whether a minimum value of the block position span 192 is within and/or outside of a threshold range of a minimum block position parameter (e.g., 3 ft, 5 ft, 10 ft, etc.) In general, the minimum block position parameter is indicative of a minimum position of the traveling block 100 that the traveling block 100 returns to after one or more drill pipes 44 are removed and before one or more drill pipes are “in-slips.” In some embodiments, the minimum block position parameter may be a value stored in memory and/or provided by an operator before and/or during the process 180 begins. For example, turning briefly to
If yes, then the processor 78 may proceed to decision block 198 of the process 180 described in more detail below. For example, the memory 80 of the data processing system 76 may include data indicative of the initial position of the traveling block 100. In some embodiments, an operator may provide the initial position before or during the LWT operations. In any case, the minimum block position parameter general indicates the lowest position the traveling block 100 may reach during the LWT operations. As such, if the processor 78 determines that the minimum value of the block position span 188 is outside of the threshold range of the minimum block position parameter, this may indicate that the traveling block 100 may be too low (e.g., the drill pipe 44 may not be entirely out of the wellbore 14) or too high (e.g., a subsequent drill pipe is partially extending out of the wellbore 14). Thus, the minimum value of the block position span 188 may not correlate with a stand break and, as such, the processor 78 may move to the next data point 189 of the bit depth data 182.
If the processor 78 determines that the minimum value of the block position span 188 does not correspond to a possible stand length of one or more drill pipes, the processor may determine whether the current in-slips minimum (e.g., associated with the determination made in decision block 184) is within and/or outside of a threshold range of a previous in-slips minimum block position value (e.g., 1%, 5%, 10% of the length of the drill pipe 44) (decision block 197). Thus, the processor 78 may confirm whether the current in-slips minimum is indicative of the drill pipe 44 being in-slips, such as when the current in-slips minimum is within the threshold range. For example, the processor 78 may compare the block position corresponding to data point 155 to the block position corresponding to data point 154 (e.g., the previous in-slips BPOS). If the processor 78 determines that the block position corresponding to data point 155 is within a threshold range of the block position corresponding to the data point 154, the processor 78 may move to decision block 198. It should be noted that the determination in decision block 197 may enable the process 180 to be flexible for some drift in the measurements of the sensors 108 that may occur during the stand break detection process. If the processor 78 determines that the block position corresponding to the data point 155 is not within the threshold range of the block position corresponding to the data point 154, then the processor 78 may determine that this is not a valid stand break, and thus, move to the next bit depth data 182.
When the processor 78 determines that the minimum value of the block position span 188 is within of a threshold range of the minimum block position parameter, the processor may then compare the minimum value of the block position span 188 to the minimum block position parameter stored in the memory 80 (decision block 198). If the minimum value of the block position span 188 is less than the minimum block position parameter stored in the memory 80, the processor may replace the current minimum block position parameter with the minimum value 200 of the block position span 188 such that runs of the process 160 may use this new value. Then, the process 180 will continue with block 202.
When the processor 78 determines that the minimum value of the block position span is greater than the minimum block position parameter stored in the memory 80, the processor 78 may determine how many pipes are in the stand break and/or the length of pipes in the stand break. For example, the processor 78 may determine whether the current bit depth of the bit depth data 182 is indicative of 1, 2, 3, 4, 5, and 6 lengths of pipe and/or within a suitable error (e.g., approximately (1%, 2%, 5%, 10%, and the like) (process block 202).
In some embodiments, the processor 78 may also determine whether the bit depth data 182 is indicative of any errors that may occur during LWT operations. For example, if the bit depth data 182 received by the processor 78 does not change after a time threshold (e.g., 10 minutes, 15 minutes, 20 minutes, 30 minutes, etc.), the processor 78 may generate an alert and output the alert the display 84 and/or I/O device 112 of the data processing system. Additionally or alternatively, the processor 78 may also determine whether the processor 78 is receiving data from the sensors 108. Upon determination by the processor 78 that the processor 78 is not receiving data, the processor 78 may generate and/or output an alert. In some embodiments, the processor 78 may determine whether the bit depth moved greater than a threshold distance from the previous bit depth, which may indicate that the drill string 16 is being lowered too quickly. In this manner, the techniques of the present disclosure may reduce and/or prevent certain events from occurring during LWT operations.
Accordingly, the present disclosure relates to techniques for stand break detection and/or converting measurements as a function of time obtained during LWT operations to measurements as a function of position (e.g., depth) within the wellbore. In some embodiments, the techniques include identifying a stand break based on sensor data obtained by at least one sensor disposed on components of a rig. In some embodiments, the techniques include outputting a portion of the sensor data corresponding to drill pipes being raised out of the wellbore based on the identified stand break. Further, the techniques may include determining a length of the one or more drill pipes that are removed as well as converting one or more measurements as function of time (e.g., obtained by a well logging tool being removed from a wellbore by the tripping out system). For example, a processor may receive sensor data as a function of time obtained via one or more components of the tripping out system and determines characteristic features of the sensor data that are indicative of the one or more drill pipes being removed from the drill string. In some embodiments, the techniques include correlating a detected stand break to a length of one or more drill pipes that were removed from the drill string. Additionally, at least in some embodiments, the techniques include converting one or measurements as a function of time that were obtained during LWT operations into one or more measurements as a function of position based on the length of the one or more drill pipes that were removed. In this way, the techniques of the present disclosure may reduce the amount of input provided by operators and at least partially automate certain steps of the stand break detection process, which may reduce costs associated with LWT operations.
The specific embodiments described above have been shown by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms. It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover all modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure.
