EP3294989B1 - Caractérisation de dysfonctionnement à perte de puissance - Google Patents

Caractérisation de dysfonctionnement à perte de puissance Download PDF

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Publication number
EP3294989B1
EP3294989B1 EP16793454.6A EP16793454A EP3294989B1 EP 3294989 B1 EP3294989 B1 EP 3294989B1 EP 16793454 A EP16793454 A EP 16793454A EP 3294989 B1 EP3294989 B1 EP 3294989B1
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Prior art keywords
wellbore
drilling
drill string
time series
sensor
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German (de)
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EP3294989A1 (fr
EP3294989A4 (fr
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Hector M. Klie
Phil D. Anno
Stacey C. RAMSAY
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ConocoPhillips Co
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ConocoPhillips Co
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Priority claimed from PCT/US2016/031864 external-priority patent/WO2016183205A1/fr
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    • 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
    • E21B44/02—Automatic control of the tool feed
    • E21B44/04—Automatic control of the tool feed in response to the torque of the drive ; Measuring drilling torque

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  • the present invention relates generally to detection and mitigation of drilling dysfunctions. More particularly, but not by way of limitation, embodiments of the present invention include predicting real-time dysfunctions at any location of a drill string by modeling a wellbore environment to enable recovery of signal energy from a drill string under operating conditions that allows for the detection and mitigation of downhole drilling dysfunctions, dysfunctions detected by sensors on the surface.
  • Hydrocarbon reservoirs are developed with drilling operations using a drill bit associated with a drill string rotated from the surface or using a downhole motor, or both using a downhole motor and also rotating the string from the surface.
  • a bottom hole assembly (BHA) at the end of the drill string may include components such as drill collars, stabilizers, drilling motors and logging tools, and measuring tools.
  • a BHA is also capable of telemetering various drilling and geological parameters to the surface facilities.
  • Resistance encountered by the drill string in a wellbore during drilling causes significant wear on drill string, especially often the drill bit and the BHA. Understanding how the geometry of the wellbore affects resistance on the drill string and the BHA and managing the dynamic conditions that lead potentially to failure of downhole equipment is important for enhancing efficiency and minimizing costs for drilling wells.
  • Various conditions referred to as drilling dysfunctions that may lead to component failure include excessive torque, shocks, bit bounce, induced vibrations, bit whirl, stick-slip, among others. These conditions must be rapidly detected so that mitigation efforts are undertaken as quickly as possible, since some dysfunctions can quickly lead to tool failures.
  • Timing information for borehole or drill string time-series data acquired with down hole sensors are important for aggregating information from surface and down hole sensors.
  • each sensor may have its own internal clock or data from many sensors may be acquired and recorded relative to multiple clocks that are not synchronized. This non-synchronization of the timing information creates problems when combining and processing data from various sensors.
  • sensor timing is known sometimes to be affected by various environmental factors that cause variable timing drift that may differentially impact various sensors. Many factors may render inaccurate the timing of individual sensors that then needs to be corrected or adjusted so the data may be assimilated correctly with all sensor information temporally consistent in order to accurately inform a drilling operations center about the dynamic state of the well being drilled.
  • Downhole drilling dysfunctions can cause serious operational problems that are difficult to detect or predict. The more rapidly and efficiently drilling dysfunctions are identified the more quickly they may be mitigated. Thus a need exists for efficient methods, systems and apparatuses to quickly identify and to mitigate dysfunctions during drilling operations.
  • US2002/0120401A1 describes a system for taking downhole measurements involving time series which also measures wellbore geometry.
  • WO2015/026317A1 describes determining drill string dysfunctions by measuring power loss in signal propagation.
  • US2012/0120763A1 describes the use of alpha and beta parameters in characterizing a subsurface environment.
  • Fig. 1 illustrates an example of a subterranean formation with a first wellbore and a second wellbore according to various embodiments of the present disclosure.
  • the various embodiments disclosed herein are used in the well drilling environment as illustrated in Fig. 1 wherein a well bore 102 is drilled from surface drilling rig facilities 101 comprising a drilling rig, drill string associated sensors, 103, to obtain data telemetered in the drill string from within the wellbore, for example an electronic acoustic receiver attached on the Kelly or blow-out preventer, as well as associated control and supporting facilities, 105, which may include data aggregation, data processing infrastructure including computer systems as well as drilling control systems.
  • the well bore 102 includes a drill string comprising an associated bottom hole assembly (BHA) that may include a mud motor 112, an adjustable bent housing or 'BHA Dynamic Sub' 114 containing various sensors, transducers and electronic components and a drill bit 116.
  • BHA bottom hole assembly
  • the BHA Dynamic Sub acquire time series data such as RPM, torque, bending moment, tension, pressure (ECS) and vibration data. Additionally, the BHA acquires measurement-while-drilling and logging-while-drilling (MWD/LWD) data in high fidelity or standard modes, such as inclination, azimuth, gamma ray, resistivity and other advanced LWD data. Any data acquired with the BHA may be transmitted to the drilling rig 101 through drill string telemetry or through mud-pulse telemetry as time series data.
  • the drill string may also contain associated sensors, for example mid-string dynamic subs 110 that acquire high fidelity time series data such as RPM, torque, bending moment, tension and vibration data, and these instrumented subs can send signals representing these measurements by telemetry up the drill string where they are also recorded on or near the drilling rig.
  • mid-string dynamic subs 110 that acquire high fidelity time series data such as RPM, torque, bending moment, tension and vibration data, and these instrumented subs can send signals representing these measurements by telemetry up the drill string where they are also recorded on or near the drilling rig.
  • the instrumented subs will not be required for wellbore 104, since sensors associated with the drill string for wellbore 104, which sensors are on or near the rig on the surface of the earth, combined with the geometry information and other time series data received by telemetry from the BHA associated with the drill string for the second wellbore, are all that are required to determine the downhole dynamics associated with the drilling operations, so that dysfunctions may be detected and mitigated effectively.
  • Embodiments disclosed herein provide for predicting real-time drilling dysfunctions at any location of a drill string.
  • the various embodiments disclosed herein provide advantages that include: (a) simplicity to detect and model a wide range of possible power losses through only three parameters; (b) determinations of down hole conditions that are well posed and amenable to stable estimation of parameters at different scales; (c) flexibility for use with different bending functions and signal representations (e.g., mean, envelope values); (d) efficiency for predicting dysfunctions by way of power-loss determinations at any point in time/depth, and therefore useful for measuring and understanding dynamic downhole conditions through measurements acquired at the surface drilling facilities associated with the drill string, so that similarly situated wells may drilled without using mid-string dynamic subs and only using surface acquired data to characterize the dynamic downhole environment during drilling operations.
  • sensors are placed at different wellbore locations, drill string locations and time/depth intervals to provide real-time measurements such as revolutions per minute (RPM), torques, weight on bit (WOB) and accelerations, etc.
  • RPM revolutions per minute
  • WOB weight on bit
  • the data acquired with these sensors may be irregularly distributed and subject to transmission losses due to absorption, scattering, and leakage induced by bending effects of the well trajectory.
  • the nonlinear combination of these effects causes an important attenuation or power-loss of signal amplitudes that may compromise the integrity and prediction of dysfunctions taking place at multiple sections of the drill string along a wellbore.
  • the present invention provides a simple but powerful power-loss model that predicts the decay of the signal energy under arbitrary bending effects due to the geometries of the well bore.
  • An understanding of the power-loss along the wellbore provided by the power-loss model facilitates an understanding of the dynamic downhole conditions, including dysfunctions, as the well is being drilled.
  • the power-loss model depends on a set of 3 parameters: one parameter, alpha ( ⁇ ), for controlling losses along the vertical section (i.e., regardless of bending effects) and two parameters, beta ( ⁇ ) and gamma ( ⁇ ), that controls the trade-off between exponential and hyperbolic signal decays for a given bending function or wellbore geometry.
  • the power-loss model combines analogs of slab (rigid) and fiber (soft) model losses that are similar to models proposed in Optics [Hunsperger, 2009 ] and Photonics [Pollock, 2003 ].
  • the presently disclosed embodiments comprise, but are not limited to, three different bending functions relative to wellbore geometries that may be described by mathematical relationships using ⁇ , ⁇ and ⁇ : 1) a geometrical tortuosity, 2) cumulative dog-leg and 3) clamping efficiency.
  • Borehole tortuosity is inherent to drilling and is the undulation from the planned well bore trajectory, such as spiraling in vertical sections or a slide-rotary behavior in horizontal sections.
  • a dog-leg is a crooked place in a wellbore where the trajectory of the wellbore deviates from a straight path.
  • a dog-leg may be created intentionally in directional drilling to turn a wellbore to a horizontal path, for example with nonconventional shale wells.
  • the standard calculation of dogleg severity is expressed in two-dimensional degrees per 100 feet, or degrees per 30 meters, of wellbore length.
  • the increasing use of sensors in real-time downhole operations is useful to investigate the wellbore environment during the drilling process and to measure the actual geometry of the wellbore.
  • the possibilities for modeling power-loss of signals travelling up the drill string as a result of wellbore geometry may now be addressed in instrumented drilling practices.
  • the models are generally governed by exponential decay functions. These functions may adopt different forms to accommodate different types of materials, to capture other loss sources on bending geometries such as those produced by micro-bending and sudden or relatively rapid changes in curvature.
  • Advantages of the bending function models disclosed herein include: (a) simplicity to accommodate a wide range of possible losses through various mathematical descriptions using combinations of three model parameters, herein designated as ⁇ , ⁇ and ⁇ ; (b) a well posed model or model group that is amenable to stable estimation of its parameters at different scales; (c) flexibility to be used with different bending functions and signal representations (e.g., mean, envelope values); and (d) efficiency for predicting dysfunction using the power-loss at any point in time/depth along the drill string leading to efficient and timely dysfunction mitigation.
  • Low-frequency surface data such as RPM, weight-on-bit (WOB), torque on bit (TOB) and acceleration data are routinely used to discover and mitigate drilling dysfunctions.
  • RPM weight-on-bit
  • TOB torque on bit
  • wave optics and photonics literature provide analogs useful for understanding transmission losses such as absorption, scattering and leakage through different materials that are subject to bending effects, such as are imposed by the geometries within a wellbore.
  • R is the radius of curvature
  • ⁇ is a situationally dependent magnitude constant
  • ⁇ and ⁇ are parameters related to bending or radius in an exponential or hyperbolic sense.
  • Various embodiments of the present disclosure provide a Hybrid Slab/Fiber Model for Power-Loss.
  • the implementation of various preferred embodiments for characterizing or modeling the power-loss dysfunction includes an option to select or model a selected bending function (i.e., geometrical tortuosity, dog-leg and clamping efficiency). Also, options to experiment with different fitting options may be derived using these model parameters. In addition, it is possible to define fitting geometries from any given starting depth. There are also definitions provided by applications of the model parameters for different smoothing and filtering options. Slab and fiber models are available to estimate power-loss by inversion using a combination of surface sensor time series data compared to equivalent down hole sensor time series data. Regressions can be performed on data for any sensor or aggregated data from some or all sensors.
  • the numerator and denominator of the last term of this equation is illustrated in Fig. 2 .
  • ⁇ k arccos cos i 1 , k ⁇ cos i 2 , k + sin i 1 , k ⁇ sin i 2 , k ⁇ cos Az 2 , k ⁇ Az 1 , k ⁇ 100 MD k .
  • the geometrical tortuosity bending function, ⁇ from Survey Station 1 to Survey Station 2 is measured two ways, which comprise the numerator ⁇ TVD k ,NS k ,EW k ⁇ 2 and the denominator MD k .
  • the denominator is the actual geometry as measured along the wellbore between Survey Station 1 and Survey Station 2, for example using data acquired from a BHA, while the numerator is the idealized measurement based on the square root of the sum of the squares of the vertical distance ( TVD k ), the North to South distance ( NS k ) and the East to West distance ( EW k ), also taking into consideration the azimuth Az 1 and inclination I 1 of the drill string at Survey Station 1 and the azimuth Az 2 and inclination I 2 of the drill string at Survey Station 2.
  • clamping efficiency parameters may be described in physics-based formulation where forces acting on the drill pipe are viewed as illustrated in Fig. 3 at the bend in the trajectory designated as ( ⁇ , ⁇ ) inclination and azimuth, respectively.
  • the force along the trajectory of the drill string is F t , for the tensional or transverse forces on the drill string in the direction of the wellbore trajectory, while the force normal to the wellbore trajectory at that point is F n .
  • the force in the other directions from the trajectory of the drill string trajectory at the bend is F t + ⁇ F t , which forces are associated directionally as ( ⁇ + ⁇ 0 ⁇ , ⁇ + ⁇ 0 ⁇ ) due to the bending.
  • the weight of the drill string is designated W.
  • W The weight of the drill string
  • Fig. 4 illustrates a process for determining real-time drilling dysfunctions by measuring power-loss of signal propagation associated with a drill string.
  • a (first) well is drilled with an instrumented drill string wherein the drill string includes a mid-string drilling sub unit to acquire and send time series data by telemetry to the surface 401.
  • a first time series is acquired from a sensor associated with a mid-string drilling sub unit in a wellbore wherein the sensor is below the surface of the earth 403.
  • a second time series is acquired from a sensor associated with a drill string, the drill string in a wellbore, wherein the sensor associated with the drill string is on or near the surface of the earth, for example associated with an acoustic receiver attached to the Kelly or other rig component for acquiring the signal.
  • a geometry of the wellbore is determined, 405, from data acquired from a bottom hole assembly that is telemetered to the surface.
  • Model parameters that describe the wellbore signal propagation power losses due to geometrical effects are determined using the first time series, the second time series and the geometry of the wellbore to derive parameters alpha and beta that characterize a power loss of signal propagation for signal travelling through the drill string based on attenuation caused by the geometry of the wellbore 409 among other dynamic effects.
  • the differential power-loss between various sensors at various locations may aid characterization. Analysis of the differential power-loss effects of various time-series comparison allows for detection and then mitigation of drilling dysfunctions.
  • a second well may be drilled wherein the drill string does not include mid string drilling sub units that acquire and send time series data into the drill string 411.
  • the dynamic state of a second well drill string in a second wellbore may be determined from a third time series data acquired from a sensor associated with a drill string in a wellbore, wherein the sensor is on or near the surface of the earth (i.e., associated with an acoustic sensor on the Kelly), and the third time series data are combined with BHA telemetered data and the model parameters determined from the first well 413.
  • Drilling dysfunctions in drilling the second well may be detected and mitigated using the third time series 415, the model parameters derived from the first wellbore and the geometry of the second wellbore.
  • Fig. 5 illustrates a system including a mid-string drilling sub sensor ( 110 ) associated with a drill string in a wellbore in a first well for acquiring a first time series 501.
  • a sensor associated with the first well drill string for acquiring a second time series wherein the sensor is on a drilling rig or near the surface of the earth 503.
  • a bottom hole assembly 112, 114, 116 associated with the drill string in a well bore 102 provides data to determine a geometry 505 of the first wellbore 102.
  • a first computer program module determines model parameters, using the first time series, the second time series and the wellbore geometry, to derive model parameters alpha and beta that characterize a power loss for signal propagation signal travelling through the drill string, 507.
  • the system may further comprise a second well drill string in a well bore 104 wherein the drill string does not include mid string drilling sub units that acquire and send time series data into the drill string, 509.
  • the system may also further comprise a second well drill string associated sensor 103 wherein the sensor is on or near the surface of the earth (for example an acoustic sensor associated with the Kelly) to provide data for determining the dynamic state of the second well drill string in the wellbore from a third time series acquired from the sensor combined with the determined model parameters from the first well, 511.
  • the system may further comprise a second computer program module determining drilling dysfunctions in drilling the second well, dysfunctions determined using the determined model parameters from the first well, the third time series and geometry of the second wellbore as derived from the BHA data associated with the second drill string, 513.
  • the system may further comprise a third computer third computer program module for mitigating the drilling dysfunctions in drilling the second well 515.
  • Fig. 6 illustrates the use of a drilling apparatus for drilling multiple wells 601 comprising a drill rig 101 with a first drill string in a well bore 102 for drilling a first well with a mid-string sub sensor 110 associated with the drilling string for acquiring a first time series 603.
  • a second sensor 103 associated with the drill string in a well bore 102 wherein the second sensor is on or near the drill rig 101 at the surface of the earth, the second sensor for acquiring a second time series 605.
  • a bottom hole assembly 112,114,116 is associated with the drill string to provide data to determine a geometry of a wellbore associated with drill string in a well bore 102.
  • the apparatus comprises a first computer program module for determining model parameters, using the first time series, the second time series and the geometry of the wellbore to derive model parameters alpha and beta that characterize a power loss of signal propagation for signal travelling through the drill string in the wellbore 609.
  • a second well may be drilling wherein the drill string does not include a mid-string drilling sub unit 611.
  • a bottom hole assembly 112, 114, 116 may be associated with the second drill string in a well bore 104 to provide data to determine a geometry of a second wellbore 613 and to provide time series data for comparison with a drill string associated sensor on the surface 103, providing a third time series 615 in order to derive signal power loss along the drill string in the wellbore and to determine drilling dysfunctions as the well is being drilled.
  • these parameters may be used in the drilling of a second well wherein the geometry data of the second well, the third time series data (such as from sensor 103 ) combined with BHA time series data to derive power loss information related to the second wellbore may be inverted to detect and then mitigate drilling dysfunctions in drilling operations.
  • a second computer program module may determine parameter gamma that with alpha and beta may be used to characterize a power loss of signal propagation for signal travelling in either the first or the second drill string.
  • a dysfunction detection computer program module may determine a dynamic state of the second drill string in a wellbore. When a drilling dysfunction is detected, measures may be taken to mitigate the dysfunction.
  • Fig. 7 is a schematic diagram of an embodiment of a system 700 that may correspond to or may be part of a computer and/or any other computing device, such as a workstation, server, mainframe, super computer, processing graph and/or database.
  • System 700 may be associated with surface infrastructure facilities 105 on a drilling rig 101.
  • the system 700 includes a processor 702, which may be also be referenced as a central processor unit (CPU).
  • the processor 702 may communicate and/or provide instructions to other components within the system 700, such as the input interface 704, output interface 706, and/or memory 708.
  • the processor 702 may include one or more multi-core processors and/or memory (e.g., cache memory) that function as buffers and/or storage for data.
  • processor 702 may be part of one or more other processing components, such as application specific integrated circuits (ASICs), field-programmable gate arrays (FPGAs), and/or digital signal processors (DSPs).
  • ASICs application specific integrated circuits
  • FPGAs field-programmable gate arrays
  • DSPs digital signal processors
  • Fig. 7 illustrates that processor 702 may be a single processor, it will be understood that processor 702 is not so limited and instead may represent a plurality of processors including massively parallel implementations and processing graphs comprising mathematical operators connected by data streams.
  • the processor 702 may be configured to implement any of the methods described herein.
  • Memory 708 may be operatively coupled to processor 702.
  • Memory 708 may be a non-transitory medium configured to store various types of data.
  • memory 708 may include one or more memory devices that comprise secondary storage, read-only memory (ROM), and/or random-access memory (RAM).
  • the secondary storage is typically comprised of one or more disk drives, optical drives, solid-state drives (SSDs), and/or tape drives and is used for non-volatile storage of data.
  • the secondary storage may be used to store overflow data if the allocated RAM is not large enough to hold all working data.
  • the secondary storage may also be used to store programs that are loaded into the RAM when such programs are selected for execution.
  • the ROM is used to store instructions and perhaps data that are read during program execution.
  • the ROM is a non-volatile memory device that typically has a small memory capacity relative to the larger memory capacity of the secondary storage.
  • the RAM is used to store volatile data and perhaps to store instructions.
  • the memory 708 may be used to house the instructions for carrying out various embodiments described herein.
  • the memory 708 may comprise a computer program module 710 that may be accessed and implemented by processor 702.
  • application interface 712 may be stored and accessed within memory by processor 702.
  • the program module or application interface may perform signal processing and/or conditioning of the time series data as described herein.
  • Programming and/or loading executable instructions onto memory 708 and processor 702 in order to transform the system 700 into a particular machine or apparatus that operates on time series data is well known in the art.
  • Implementing instructions, real-time monitoring, and other functions by loading executable software into a computer can be converted to a hardware implementation by well-known design rules. For example, decisions between implementing a concept in software versus hardware may depend on a number of design choices that include stability of the design and numbers of units to be produced and issues involved in translating from the software domain to the hardware domain.
  • Often a design may be developed and tested in a software form and subsequently transformed, by well-known design rules, to an equivalent hardware implementation in an ASIC or application specific hardware that hardwires the instructions of the software.
  • a machine controlled by a new ASIC is a particular machine or apparatus, likewise a computer that has been programmed and/or loaded with executable instructions may be viewed as a particular machine or apparatus.
  • Fig. 7 illustrates that the processor 702 may be operatively coupled to an input interface 704 configured to obtain the time series data and output interface 706 configured to output and/or display the results or pass the results to other processing.
  • the input interface 704 may be configured to obtain the time series data via sensors, cables, connectors, and/or communication protocols.
  • the input interface 704 may be a network interface that comprises a plurality of ports configured to receive and/or transmit time series data via a network.
  • the network may transmit the acquired time series data via wired links, wireless link, and/or logical links.
  • Other examples of the input interface 704 may be universal serial bus (USB) interfaces, CD-ROMs, DVD-ROMs.
  • the output interface 706 may include, but is not limited to one or more connections for a graphic display (e.g., monitors) and/or a printing device that produces hard-copies of the generated results.
  • a condition number provides a validation of how well posed, or sensitive, the power loss model is to changes in the bending function:
  • a process for determining real-time drilling operations dysfunctions measures a power-loss of signal propagation associated with a drill string
  • the process comprises acquiring a first time series from a mid-string drilling sub sensor associated with a drill string in a wellbore in a first well and acquiring a second time series from a sensor associated with the drill string wherein the sensor is on or near a drill rig on the surface of the earth.
  • the process further comprises determining the geometry of the wellbore and determining model parameters alpha and beta for characterizing a wellbore using the first time series, the second time series and the geometry of the wellbore by deriving a power loss of signal propagation.
  • a further aspect may comprise drilling a second well wherein the drill string does not include mid string drilling sub units that acquire and send time series data into the drill string.
  • a further aspect may comprise drilling a second well and acquiring a third time series from a sensor associated with a drill string in a wellbore wherein the sensor is on or near the drill rig on the surface of the earth. Drilling dysfunctions may be mitigated in drilling the second well, wherein the dysfunctions are determined using the determined model parameters alpha and beta, the third time series and geometry of the second wellbore.
  • the process may further comprise deriving parameter gamma, that with alpha and beta characterize a power loss dysfunction of signal propagation for signal travelling through the drill string.
  • the process may further comprise determining, using alpha, beta and optionally gamma, at least one selected from the group of i) a geometrical tortuosity, ii) a cumulative dog-leg value, and iii) a clamping efficiency.
  • a system for determining real-time drilling operations dysfunctions by measuring power-loss of signal propagation associated with a drill string during drilling a wellbore where the system comprises a mid-string drilling sub sensor associated with a drill string in a wellbore in a first well for acquiring a first time series and a sensor associated with the first well drill string for acquiring a second time series wherein the sensor for acquiring the second time series is on a drilling rig or near the surface of the earth.
  • a bottom hole assembly associated with the drill string provides data to determine a geometry of the first wellbore
  • a computer with a processor and memory further comprises a first computer program module to determine model parameters alpha and beta that characterize a wellbore using the first time series, the second time series and the geometry of the wellbore by deriving a power loss of signal propagation.
  • the system may further comprise a second well drill string wherein the drill string does not include mid string drilling sub units that acquire and send time series data into the drill string.
  • the system may comprise a second well drill string associated sensor wherein the sensor is on or near the surface of the earth to provide data for determining the dynamic state of the second well drill string in the wellbore from a third time series data acquired from the sensor combined with the determined model parameters.
  • the system may further comprise a second computer program module for determining drilling dysfunctions in drilling the second well, dysfunctions determined using the determined model parameters, the third time series and geometry of the second wellbore.
  • a third computer program module may be provided for mitigating the drilling dysfunctions in drilling the second well.
  • a fourth computer program module may be provided that determines a parameter gamma, that with alpha and beta may be used to characterize a power loss dysfunction of signal propagation for signal travelling through the drill string.
  • a drilling rig apparatus for drilling multiple wells, where the apparatus comprises a drill rig with a first drill string for drilling a first well and a mid-string drilling sub sensor associated with the drill string for acquiring a first time series, as well as a second sensor associated with the drill string wherein the second sensor is on or near the drill rig at the surface of the earth, the second sensor for acquiring a second time series. Also provided is a bottom hole assembly associated with the drill string to provide data to determine a geometry of a wellbore.
  • a computer with a processor and memory may be provided, which has one or more application interfaces and one or more computer program modules.
  • a first computer program module may be provided for determining model parameters, using the first time series, the second time series and the geometry of the wellbore to derive model parameters alpha and beta that characterize a power loss of signal propagation for signal travelling through the drill string.
  • the apparatus may further comprise a second well drill string wherein the drill string does not include mid string drilling sub units that acquire and send time series data into the second drill string.
  • the apparatus may comprise a bottom hole assembly associated with the second drill string providing data to determine a geometry of a second wellbore.
  • a second well drill string associated sensor may be provided wherein the sensor is on or near the drill rig at the surface of the earth to acquire a third time series.
  • a second computer program module may be provided that determines parameter gamma that with alpha and beta may be used to characterize a power loss dysfunction of signal propagation for signal travelling through the first or second drill string.
  • a dysfunction-detection computer program module may be provided for determining a dynamic state of the second drill string in a wellbore.
  • a dysfunction-mitigation computer program module may be provided for mitigating drilling dysfunctions detected associated with a drill string in a wellbore.

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Claims (4)

  1. Procédé pour déterminer les dysfonctionnements de forage en temps réel dans lequel le procédé comprend :
    a. l'acquisition d'une première série temporelle à partir d'un sous capteur de forage de milieu de tige (110) associé à une tige de forage dans un puits de forage dans un premier puits (102) ;
    b. l'acquisition d'une seconde série à partir d'un capteur associé à la tige de forage dans lequel le capteur est sur ou à proximité d'une installation de forage (101) sur la surface de la terre ;
    c. la détermination de la géométrie du puits de forage ; caractérisé en ce que le procédé mesure la perte de puissance de la propagation de signal associée à une tige de forage pour forer un puits par :
    d. la détermination de paramètres de modèle alpha et bêta pour caractériser un puits de forage en utilisant la première série temporelle, la seconde série temporelle et la géométrie du puits de forage en dérivant une perte de puissance de la propagation de signal ; et caractérisé en outre en ce que
    e. le procédé comprend en outre le forage d'un second puits (104) et l'acquisition d'une troisième série temporelle d'un capteur associé à une tige de forage dans un puits de forage dans lequel le capteur se trouve sur ou à proximité de l'installation de forage (101) sur la surface de la terre, comprenant en outre l'atténuation des dysfonctionnements de forage lors du forage du second puits, les dysfonctionnements étant déterminés en utilisant les paramètres de modèle déterminés alpha et bêta, la troisième série temporelle et la géométrie du second puits de forage.
  2. Procédé selon la revendication 1, dans lequel la détermination des paramètres de modèle comprend en outre la dérivation des paramètres gamma, qui avec alpha et bêta caractérisent un dysfonctionnement de perte de puissance de la propagation de signal pour le signal circulant à travers la tige de forage.
  3. Procédé selon la revendication 2, dans lequel la détermination des paramètres de modèle, en utilisant la première et la seconde série temporelles, comprend en outre une estimation de paramètre à deux étapes : (1) ln(P 0,j /Pi,j ) + aizi = 0 pour i = 1,2,··· , Nz ; j = 1,2,···,Ns et (2) a i = αe − βτ i τ i − γ ,
    Figure imgb0012
     étant le problème des trois paramètres pour prendre en compte les effets de fibre/dalle combinés dans lesquels i est sur la profondeur et j varie selon les stations d'échantillonnage.
  4. Procédé selon la revendication 2, comprenant en outre la détermination, en utilisant alpha, bêta et gamma, d'au moins un étant sélectionné à partir du groupe constitué par i) une tortuosité géométrique, ii) une valeur coudée cumulative, et iii) une efficacité de serrage.
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US5115872A (en) * 1990-10-19 1992-05-26 Anglo Suisse, Inc. Directional drilling system and method for drilling precise offset wellbores from a main wellbore
US6732052B2 (en) * 2000-09-29 2004-05-04 Baker Hughes Incorporated Method and apparatus for prediction control in drilling dynamics using neural networks
US7791724B2 (en) * 2006-06-13 2010-09-07 Asml Netherlands B.V. Characterization of transmission losses in an optical system
RU2475784C2 (ru) * 2007-12-19 2013-02-20 Эксонмобил Апстрим Рисерч Компани Моделирование характеристики гамма-лучевого каротажного зонда
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WO2015026317A1 (fr) * 2013-08-19 2015-02-26 Halliburton Energy Services, Inc. Évaluation de systèmes de télémétrie de puits de forage
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