WO2010101548A1 - Analyse et commande du mouvement d'un train de tiges - Google Patents

Analyse et commande du mouvement d'un train de tiges Download PDF

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Publication number
WO2010101548A1
WO2010101548A1 PCT/US2009/001418 US2009001418W WO2010101548A1 WO 2010101548 A1 WO2010101548 A1 WO 2010101548A1 US 2009001418 W US2009001418 W US 2009001418W WO 2010101548 A1 WO2010101548 A1 WO 2010101548A1
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WO
WIPO (PCT)
Prior art keywords
drillstring
indications
amplitude
bit
empirical mode
Prior art date
Application number
PCT/US2009/001418
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English (en)
Inventor
Paul F. Rodney
Original Assignee
Halliburton Energy Services, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to US13/054,900 priority Critical patent/US20110153217A1/en
Priority to PCT/US2009/001418 priority patent/WO2010101548A1/fr
Publication of WO2010101548A1 publication Critical patent/WO2010101548A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/007—Measuring stresses in a pipe string or casing
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions

Definitions

  • a number of undesirable conditions can develop while drilling a borehole.
  • standing vibration waves can be generated along the drillstring, leading to a condition known as stick/slip.
  • the drillstring stops rotating for a period of time, and then spins free.
  • the resulting instantaneous rotation frequency can be high enough to loosen the coupling between drillstring elements.
  • Another condition is known as whirl, in which the bit, or a portion of the drillstring, rotates around the circumference of the borehole (instead of substantially centered within the borehole). This can quickly become a chaotic phenomenon in which the drillstring seems to randomly bounce back and forth, slapping against the sides of the borehole.
  • FIG. 1 illustrates accelerometer signal modal decomposition according to various embodiments of the invention.
  • FIG. 2 illustrates apparatus that operates to decompose accelerometer signals according to various embodiments of the invention.
  • FIG. 3 illustrates systems according to various embodiments of the invention.
  • FIG. 4 is a flow chart illustrating several methods according to various embodiments of the invention.
  • FIG. 5 is a block diagram of an article according to various embodiments of the invention.
  • Time series measurements made using accelerometers and other motion-sensitive sensors can be used to diagnose undesirable vibration phenomena that occur as part of drilling operations. Because of inter-related effects, a reliable diagnosis can be difficult to make when several phenomena exist simultaneously. However, if enough motion-sensitive sensors are used, along with instrumentation for real-time standoff measurements, the various modes of drillstring motion can be isolated by combining the sensor outputs. Unfortunately, due to constraints on funding and computer resources, this type of operation is not practical.
  • a mechanism is disclosed herein that permits identifying various modes of vibrational motion presented by a bottom hole assembly (BHA) using a single measurement vehicle (e.g., a single accelerometer).
  • a single measurement vehicle e.g., a single accelerometer.
  • the entire analysis may be carried out downhole and used to stabilize a downhole drilling motor, a rotary steerable device, an adjustable blade stabilizer, a controllable shock sub, and other components having functions that affect drillstring operational parameters.
  • the operations disclosed can be carried out in a higher-dimension space to incorporate a plurality of measurements.
  • FIG. 1 illustrates accelerometer signal modal decomposition according to various embodiments of the invention.
  • a sequence of signal data is shown in graph 100, as acquired from a single downhole accelerometer attached to a drillstring while the drillstring was operating in a stick/slip mode.
  • the hesitation of the drillstring is clearly visible in graph 100 at time intervals centered around 0.7 seconds, 3 seconds and 5.1 seconds. Because of the shortness of the time interval, the temporal and spectral resolution for a conventional spectrogram (e.g., using Fourier analysis) would be relatively poor.
  • the empirical mode decomposition of signals is well known to those of ordinary skill in the art.
  • Modes 1 and 2 represent high frequency events that are likely not related to stick/slip.
  • Mode 3 i.e., graph 106) represents a process that starts at about 1 second, dies down at about 2.5 seconds, and restarts at about 3 seconds. As with the base waveform (shown in graph 100), the process appears to be substantially repeatable, although this is not always the case.
  • Mode 4 i.e., graph 106) represents a more or less continuous mode upon which the stick/slip has been superimposed.
  • the base waveform signal that results from continuous drilling represented in graph 100 can be represented by the sum of modes 4, 5, 6 and the residual (i.e., graphs 108, 110, 1 12, and 114).
  • a mode (e.g., any one of modes mode-1 through mode-6) can be expressed in the form:
  • the amplitude 130 of one or more of the modes can be monitored continuously for excursions above a pre-set threshold 120.
  • a downhole or surface computer can keep track of the average of the amplitude 130 over some selected period of time and compare the values of the current amplitude 130 with this average (which may be a running average, such as an exponential average, among others).
  • the threshold can be at some fixed value, or a fixed amount above the average, or expressed as a band substantially centered on the average.
  • a predefined threshold amplitude, such as threshold 120 can be transmitted from the surface to the downhole tool using any available measurement while drilling (MWD) downlink communications channel.
  • MWD measurement while drilling
  • the amplitude and the mode number can be relayed to surface equipment, perhaps along with information about the number of high amplitude events, the mean separation in time between such events, the instantaneous frequency during the time period when the amplitude exceeded the threshold 120, an average of the instantaneous frequency during the time period when the amplitude exceeded the threshold 120, etc.
  • This information is sufficient for the driller to identify that the angular rate at which the rotary table turns needs to be changed and for the driller to determine how it needs to be changed.
  • the calculated amplitude can also be compared with that obtained using various drillstring dynamics modeling programs, thus providing a calibration point for the drillstring dynamics program that has been selected for use, while the program itself is used to select a different rotary speed.
  • mode-1 and mode-2 i.e., graphs 102
  • the modal decomposition analysis can be accomplished without recourse to Fourier techniques, and that, in comparison, Fourier techniques often provide a less complete picture of the phenomenon, because they cannot provide the frequency resolution in short time intervals that is usually possible with modal decomposition apparatus and methods.
  • FIG. 2 illustrates apparatus 200 that operates to decompose accelerometer signals according to various embodiments of the invention.
  • the signals from one or more accelerometers 284 can be acquired using a data acquisition system 260, which feeds the signals, perhaps after amplification and filtering, into an analysis module 262.
  • the analysis module 262 may be used to decompose the accelerometer signals into empirical modes.
  • the signal characteristics of the raw accelerometer signals and/or the derived empirical modes may be monitored by a monitoring module 264 to determine whether the current empirical mode signal values exceed some selected threshold, perhaps established as an absolute threshold, or as a relative threshold (e.g., a threshold riding at some distance, absolute or relative, above and/or below a running mean of the acquired amplitude). For example, a change of more than ⁇ 10% or ⁇ 20% from a running mean of the empirical mode signal amplitude values.
  • the accelerometer signals, the mode amplitude values, the mode instantaneous frequency values, and indications of the threshold being exceeded can all be transmitted from downhole to the surface 204 for further processing.
  • an apparatus 200 may comprise an analysis module
  • the apparatus 200 may also comprise a monitoring module 264 to monitor the amplitude of one or more empirical modes, and to provide indications of the amplitude exceeding a preselected threshold.
  • the apparatus 200 can be used to measure acceleration of the drillstring, or some component attached to the the drillstring, decompose the data into empirical modes, and monitor the behavior of modal data.
  • the apparatus 200 can be located on the surface 204, downhole, or various components of the apparatus 200 may be divided between the two locations.
  • a receiver 266 can be used to receive various parameters from the surface 204, such as the threshold used by the monitoring module 264.
  • the apparatus 200 may comprise a receiver 266 to receive a preselected threshold from a surface source (e.g., the logging station 292), where the receiver 266 can be coupled to the monitoring module 264 (e.g., via the analysis module, as shown in FIG. 2).
  • the analysis module 262, the monitoring module 264, or both, may be housed in a downhole tool 224.
  • the apparatus 200 may comprise a downhole tool 224 to at least partially house at least one of the analysis module 262 or the monitoring module 264.
  • a processor 254 can be used to further process modal data, perhaps to determine the amplitude of empirical modes as a function of time, and/or to maintain a running average of the amplitudes.
  • the apparatus 200 may comprise a processor 254 to derive the amplitude of one or more empirical modes and/or to display a variety of information about modal behavior on the display 296.
  • the processor 254 can be at least partially housed by the downhole tool 224 as well.
  • a transmitter 268 can be used to send many different types of information to the surface 204.
  • the apparatus 200 may comprise a transmitter 268 to transmit one or more amplitudes, running averages of amplitudes, the number of indications of one or more amplitudes exceeding one or more corresponding thresholds per unit time, or the mean separation time between the indications.
  • the transmitter 268 can be used to transmit an alert message to the surface 204, with a display of the alert message content based on the amplitude. In this way, anomalous amplitude events might be used to initiate an alarm, perhaps used to stop drilling operations.
  • FIG. 3 illustrates systems 300 according to various embodiments of the invention.
  • the system 300 may comprise more than one of the apparatus 200.
  • the apparatus 200 as described above and shown in FIG. 2, may form portions of a down hole tool 224 as part of a downhole drilling operation.
  • FIG. 3 it can be seen how a system 300 may also form a portion of a drilling rig 302 located at the surface 204 of a well 306.
  • the drilling rig 302, comprising a drilling platform 386 may be equipped with a derrick 388 that supports a drill string 308 lowered through a rotary table 310 into a wellbore or borehole 312.
  • the drill string 308 may operate to penetrate a rotary table
  • the drill string 308 may include a Kelly 316, drill pipe 318, and a BHA 320, perhaps located at the lower portion of the drill pipe 318.
  • the drill string 308 may include wired and unwired drill pipe, as well as wired and unwired coiled tubing, including segmented drilling pipe, casing, and coiled tubing.
  • the BHA 320 may include drill collars 322, a down hole tool
  • the drill bit 326 may operate to create a borehole 312 by penetrating the surface 204 and subsurface formations 314.
  • the down hole tool 224 may comprise any of a number of different types of tools including MWD tools, logging while drilling (LWD) tools, and others.
  • the drill string 308 (perhaps including the Kelly 316, the drill pipe 318, and the BHA 320) may be rotated by the rotary table 310.
  • the bottom hole assembly 320 may also be rotated by a top drive or a motor (e.g., a mud motor) that is located down hole.
  • the drill collars 322 may be used to add weight to the drill bit 326.
  • the drill collars 322 also may stiffen the BHA 320 to allow the bottom hole assembly 320 to transfer the added weight to the drill bit 326, and in turn, assist the drill bit 326 in penetrating the surface 204 and subsurface formations 314.
  • a mud pump 332 may pump drilling fluid (sometimes known by those of ordinary skill in the art as “drilling mud” or simply "mud") from a mud pit 334 through a hose 336 into the drill pipe 318 and down to the drill bit 326.
  • the drilling fluid can flow out from the drill bit 326 and be returned to the surface 204 through an annular area 340 between the drill pipe 318 and the sides of the borehole 312.
  • the drilling fluid may then be returned to the mud pit 334, where such fluid is filtered.
  • the drilling fluid can be used to cool the drill bit 326, as well as to provide lubrication for the drill bit 326 during drilling operations. Additionally, the drilling fluid may be used to remove subsurface formation 314 cuttings created by operating the drill bit 326.
  • the system 300 may include a drill collar 322, a drill string 308, and/or a down hole tool 224 to which one or more apparatus 200 are attached.
  • the down hole tool 224 may comprise an LWD tool, or an MWD tool.
  • the drill string 308 may be mechanically coupled to the down hole tool 224.
  • a system 300 may comprise a drillstring 308, one or more accelerometers 284 attached to the drillstring 308, and one or more apparatus 200, as described previously.
  • the system 300 comprises a display 296 to present rotational activity of the bit 326 coupled to the drillstring 308, perhaps based on the amplitude of one or more of the empirical modes, and the indications of the one or more modes exceeding some selected threshold. In this way, the drillstring 308 and/or bit 326 activity can be displayed to the rig operator, perhaps in graphic form.
  • the system 300 may comprise a downhole tool 224, wherein at least one of the analysis module or the monitoring module (see elements 262, 264, respectively in FIG. 2) are attached to the downhole tool 224.
  • a control system 398 can be used to modify drilling operations based on the data obtained by monitoring the empirical modes.
  • a system 300 may comprise a control system 398 to modify drillstring operational parameters comprising one or more of the rotational speed, weight on bit, or mud flow based on the indications (of exceeding a selected threshold).
  • One or more displays 296 may be included in the system 300 as part of a processor 254 in a logging station 292 to display any type of acquired data, including the raw acquired accelerometer data, empirical mode data (amplitude and/or phase), threshold data, etc.
  • the apparatus 200, downhole tool 224,processor 254, data acquisition system 260, analysis module 262, monitoring module 264, receiver 266, transmitter 268, accelerometers 284, logging facility 292, system 300, drilling rig 302, drill string 308, rotary table 310, Kelly 316, drill pipe 318, bottom hole assembly 320, drill collars 322, drill bit 326, mud pump 332, drilling platform 386, derrick 388, and control system 398 may all be characterized as "modules" herein.
  • modules may include hardware circuitry, one or more processors and/or memory circuits, software program modules and objects, and firmware, and combinations thereof, as desired by the architect of the apparatus 200 and system 300, and as appropriate for particular implementations of various embodiments.
  • such modules may be included in an apparatus and/or system operation simulation package, such as a software electrical signal simulation package, a power usage and distribution simulation package, a power/heat dissipation simulation package, and/or a combination of software and hardware used to simulate the operation of various potential embodiments.
  • an apparatus and/or system operation simulation package such as a software electrical signal simulation package, a power usage and distribution simulation package, a power/heat dissipation simulation package, and/or a combination of software and hardware used to simulate the operation of various potential embodiments.
  • Applications that may include the novel apparatus and systems of various embodiments comprise process measurement instalments, personal computers, workstations, and vehicles, among others. Some embodiments include a number of methods.
  • FIG. 4 is a method flow diagram 411 according to various embodiments of the invention.
  • a method 41 1 may begin at block 421 with obtaining acceleration data from an operational drillstring.
  • acceleration data may be obtained from a single accelerometer.
  • the activity at block 421 may include obtaining the acceleration data from a single accelerometer attached to the drillstring.
  • the method 411 may continue on to block 425 with decomposing the acceleration data into one or more empirical modes.
  • the empirical modes comprise one or more modes having a dominant frequency of about 0.2 Hz to about 500 Hz.
  • the method 41 1 may include monitoring the amplitude of the one or more empirical modes at block 429, perhaps to detect indications exceeding a preselected threshold (as determined at block 437). Thus, if a threshold has not been previously selected, or if the threshold is to be changed, the method 411 may include determining the preselected threshold at block 433 based on a running average of the amplitude of one or more modes, to detect excursions beyond normal operation. In some embodiments, the activity at block 433 includes receiving the preselected threshold (downhole) from a surface location. [0044] If the indications do not exceed the threshold, as determined at block 437, then the method 411 may return to block 421 to obtain additional accelerometer data.
  • the method 411 may continue on to block 441 with determining an average time between the indications. This is because the average time between indications that exceed the selected threshold can help determine what type of activity is occurring with the drill string and/or bit (e.g., stick/slip or whirl).
  • the rig operator can be informed of the vibrational modes that might be in existence along the drill string, or at the drill bit.
  • the activity can be stored in a log for later use.
  • the method 411 may go on to include, at block 445, publishing a report comprising one of stick/slip, bit bounce, whirling, or lateral vibration based on the indications.
  • the method 41 1 may go on to block 449 to include modifying drillstring operational parameters comprising at least one of rotational speed, weight on bit, or mud flow, based on the indications.
  • the method 411 may include acquiring acceleration data, decomposing the data into one or more empirical modes, monitoring the amplitude of at least one of the modes, and modifying drillstring operations responsive to the amplitude behavior.
  • the activity at block 449 may include reducing the rotational speed until the number of the indications per unit time falls below a selected frequency. In cases of whirling, for example, it may be the best practice to reduce the rotational speed.
  • the activity at block 449 may additionally, or alternatively include increasing the rotational speed until a number of the indications per unit time falls below a selected frequency. For example, in some cases of resonant behavior, such as stick/slip, it may be beneficial to increase the rotational speed beyond the resonant condition.
  • Dynamic phenomena such as stick/slip, whirl, bit bounce, and lateral vibration, can be identified using the apparatus and systems described herein, or as part of the disclosed methods. After individual phenomena have been identified, various embodiments can sometimes operate to correct them, or at least, to reduce their intensity, perhaps by varying the rotational bit speed, weight on bit, and/or mud flow.
  • stick/slip can be identified by the sudden appearance of a mode that has non-zero amplitude at approximately zero frequency for a period of time that is a significant fraction of what, in the short- term history of the drillstring, was the average period revolution.
  • bit whirl and collar whirl.
  • whirl may follow the appearance of a mode with an instantaneous frequency close to (or equal to) a harmonic of the rotational frequency, perhaps as determined by the historical output of one or more rotationally sensitive transducers.
  • a mode with an instantaneous frequency close to (or equal to) a harmonic of the rotational frequency, perhaps as determined by the historical output of one or more rotationally sensitive transducers.
  • a harmonic of the rotational frequency perhaps as determined by the historical output of one or more rotationally sensitive transducers.
  • Several such modes may be present simultaneously.
  • the progression of harmonic modes breaks down completely - these modes suddenly disappear and are replaced by random impulse noise.
  • the modal decompositions of the two signals are, in essence, the signals themselves.
  • the direction of rotation can be determined by calculating an angle defined as the four quadrant arctangent of the x- and y-signals provided by the orthogonal sensors, where the x-signal is provided by one sensor, and the y- signal is provided by the other. If the x-and y- signals are of different magnitudes, they can be rescaled to be of the same magnitude.
  • the direction of rotation is then determined by the change between samples of the rotation angle. Since the arctangent is a discontinuous function, there are some samples where the direction of rotation can not be determined.
  • synchronous whirl In this type of whirl, the drillstring is generally in contact with the borehole wall. This may by accompanied by slipping, but normally occurs in a direction opposite to that of the drillstring rotation. Under such conditions, it may be useful to use a different type of sensor to identify the modes, hi particular, one or more bending moment sensors can be used to produce signals indicative of the bending stress along the drillstring. Fourier analysis or modal analysis can be used to establish the presence of regular frequencies in the bending stress signals. Two or higher dimensional analyses similar to those discussed above can also be carried out with the bending moments.
  • a subspecies of synchronous whirl is one in which the same side of the drill collars or of the bit continually faces or rubs against the borehole wall. In this case, a significant level of bending will be present at the same time that all modes have diminished to a value of approximately zero.
  • Bit bounce includes a significant random component. However, some portions of the bit motion along the drillstring axis can still exhibit modal behavior.
  • a first example is when roller cone bits are used: as the formation is broken up by the bit, a regular pattern develops in the bottom of the borehole. This pattern, created by the motion of the bit, also contributes to drillstring motion of the bit.
  • the pattern typically continues to deepen until the depth contrast of the pattern is equal to (or somewhat less than) the relief across the face of the bit, at which time the bit operates to destroy the pattern. While the pattern grows, drillstring bit vibration increases. When pattern destruction occurs, drillstring axis bit vibration decreases. This is described in SPE 14330- MS Field Measurements of Downhole Drillstring Vibrations, Wolf, S.F., Zacksenhouse, M., Arian, A., 1985.
  • Bit bearing failure will modify the vibrations along the drillstring axis near the bit since a dragging cone scrapes the formation, instead of crushing it. When this happens, a change in the bit bounce vibration mode will be evident. In addition, stalling may be evident, as indicated by sensors responding to vibrations orthogonal to the drillstring axis or by rotation-sensitive sensors. This might seem to be similar to stick/slip, but because stick/slip is a standing wave phenomenon, the associated frequencies usually fall within a well-defined, reasonably predictable range. Hence, the signature of a dragging bit would be a sudden change in the normal mode of drillstring-axis vibration coupled with a broad-band modal behavior with frequencies that fall outside of the frequencies expected for stick/slip.
  • the method 411 includes calibrating a drillstring dynamics modeling program used to select a rotary speed of the drillstring, based on the indications (perhaps as used to identify the various phenomena), at block 453.
  • the activity of the bit and/or drillstring may be graphically displayed, depending on the monitored mode activity.
  • the method 411 may include displaying rotational activity of the borehole bit attached to the drillstring based on the amplitude of one or more monitored modes, and the indications (of exceeding a selected threshold).
  • Bit steering operations may also be adjusted according to the monitored mode indications.
  • the method 411 may include steering the borehole bit along a path based on feedback associated with the indications, at block 461. For example, it may turn out that steering in a particular direction to enter a softer formation type operates to lessen vibrations indicating stick/slip conditions.
  • a software program can be launched from a computer-readable medium in a computer- based system to execute the functions defined in the software program.
  • various programming languages may be employed to create one or more software programs designed to implement and perform the methods disclosed herein.
  • the programs may be structured in an object-orientated format using an object-oriented language such as Java or C++.
  • the programs can be structured in a procedure- orientated format using a procedural language, such as assembly, FORTRAN or C.
  • the software components may communicate using any of a number of mechanisms well known to those skilled in the art, such as application program interfaces or interprocess communication techniques, including remote procedure calls.
  • application program interfaces or interprocess communication techniques, including remote procedure calls.
  • remote procedure calls The teachings of various embodiments are not limited to any particular programming language or environment. Thus, other embodiments may be realized.
  • FIG. 5 is a block diagram of an article 585 according to various embodiments of the invention.
  • the article 585 comprises an article of manufacture, such as a computer, a memory system, a magnetic or optical disk, some other storage device, and/or any type of electronic device or system.
  • the article 585 may include one or more processors 587 coupled to a computer-accessible medium 589 such as a memory (e.g., fixed and removable storage media, including tangible memory having electrical, optical, or electromagnetic conductors) having associated information 591 (e.g., computer program instructions), which when executed by a computer, causes the computer (e.g., the processor(s) 587) to perform a method including such actions as obtaining acceleration data from an operational drillstring, decomposing the acceleration data into at least one empirical mode, monitoring the amplitude of the at least one empirical mode to detect indications exceeding a preselected threshold, and modifying drillstring operational parameters comprising at least one of rotational speed, weight on bit, or mud flow based on the indications.
  • a computer-accessible medium 589 such as a memory (e.g., fixed and removable storage media, including tangible memory having electrical, optical, or electromagnetic conductors) having associated information 591 (e.g., computer program instructions), which when executed by a computer, causes the computer (e.g
  • the data may be acquired using a single accelerometer. Additional actions may include, for example, determining the preselected threshold based on a running average of the amplitude, or receiving the preselected threshold from a surface location. Indeed, any of the activities described with respect to the various methods above may be implemented in this manner.
  • inventive subject matter may be referred to herein, individually and/or collectively, by the term "invention" merely for convenience and without intending to voluntarily limit the scope of this application to any single invention or inventive concept if more than one is in fact disclosed.
  • inventive subject matter may be referred to herein, individually and/or collectively, by the term "invention" merely for convenience and without intending to voluntarily limit the scope of this application to any single invention or inventive concept if more than one is in fact disclosed.
  • inventive subject matter merely for convenience and without intending to voluntarily limit the scope of this application to any single invention or inventive concept if more than one is in fact disclosed.

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Abstract

Appareil, système et procédés pouvant être utilisés pour obtenir des données d'accélération d'un train de tiges en fonctionnement, décomposer ces données d'accélération en un ou plusieurs modes empiriques, surveiller l'amplitude d'au moins un des modes empiriques pour détecter les indications dépassant un seuil présélectionné, et modifier sur la base de ces indications les paramètres de fonctionnement du train de tiges, dont la vitesse de rotation, la charge sur le trépan et/ou l'écoulement de boue. L'invention concerne également d'autres appareils, systèmes et procédés.
PCT/US2009/001418 2009-03-05 2009-03-05 Analyse et commande du mouvement d'un train de tiges WO2010101548A1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
US13/054,900 US20110153217A1 (en) 2009-03-05 2009-03-05 Drillstring motion analysis and control
PCT/US2009/001418 WO2010101548A1 (fr) 2009-03-05 2009-03-05 Analyse et commande du mouvement d'un train de tiges

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PCT/US2009/001418 WO2010101548A1 (fr) 2009-03-05 2009-03-05 Analyse et commande du mouvement d'un train de tiges

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