Patent Publication Number: US-9410377-B2

Title: Apparatus and methods for determining whirl of a rotating tool

Description:
BACKGROUND 
     1. Field of the Disclosure 
     This disclosure relates generally to determining whirl rate of rotating members, such as drilling assemblies. 
     2. Background of the Art 
     Drill strings containing a drilling assembly (also referred to as the “bottomhole assembly”) having a drill bit an end thereof are used to drill wellbores for the production of hydrocarbons from earth formations. The drill bit is rotated with weight-on-bit applied from the surface. A fluid is circulated through the drill string, drill bit and the annulus between the drill string and the wellbore to lubricate the drill bit and to carry the rock cuttings made by the drill bit to the surface. The drilling assembly and the drill bit can exhibit a variety of motions in addition to the rotation of the drill bit along a linear path. Such motions are generally referred to as dysfunctions and include vibration, displacement of the tool along a direction other than the drilling direction, bending moments and whirl. Whirl occurs in rotating members such as drill strings, drill bits, shafts, etc. Whirl (also referred to as “whirl rate,” “whirl frequency” and “whirl velocity”) of a rotating member, such as shaft, may be defined as “the rotation of the plane made by a bent shaft and the line of the centers of the bearings.” In this definition, whirl can be forward whirl (rotation in the same direction as the shaft rotation direction) or backward whirl (rotation in the opposite direction to the shaft rotation direction). When the shaft whirls at the same speed as it rotates about its axis, the whirl is said to be synchronous. In terms of drilling systems, the most violent and most frequently observed type of whirl is the backward whirl. Often whirl induces failures in the BHA components and damages the drill bit. 
     The disclosure herein provides apparatus and methods for determining the whirl rate for a rotating member, such as a drilling assembly and drill bit. 
     SUMMARY 
     In one aspect, a method of determining when whirl for a rotating tool is present is disclosed. The method in one embodiment includes: obtaining measurements (a x ) of a parameter relating to the whirl of the tool along a first axis of the tool and measurements (a y ) relating to the parameter along a second axis of the tool; determining a first whirl rate in a time domain for the tool using a x  and a y  measurement, determining a second whirl rate for the tool in a frequency domain from a x  and a y  confirming when the whirl is present from the first whirl rate and the second whirl rate. In aspects, the whirl is present when the first whirl rate and the second whirl rate meet a selected criterion. In another aspect, the method may further determine the direction and magnitude of the whirl from the first whirl rate and the second whirl rate. 
     In another aspect, an apparatus for determining when whirl is present in a rotating tool is disclosed. The apparatus in one embodiment includes sensors configured to provide measurements (a x ) of a parameter relating to the whirl of the tool along a first axis of the tool and measurements (a y ) of the parameter relating to the whirl of the tool along a second axis of the tool and a processor configured to: determine a first whirl rate for the tool in a time domain from the a x  and a y  measurements; determine a second whirl rate for the tool in a frequency domain from the a x  and a y  measurements and determining when the whirl for the tool is present from the first whirl rate and second whirl rate. In another aspect, the processor may be further configured to determine the direction and magnitude of the whirl from the first and second whirl rates. 
     Examples of certain features of the apparatus and methods disclosed herein are summarized rather broadly in order that the detailed description thereof that follows may be better understood. There are, of course, additional features of the apparatus and method disclosed hereinafter that will form the subject of the claims appended hereto. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The disclosure herein is best understood with reference to the accompanying figures in which like numerals have generally been assigned to like elements and in which: 
         FIG. 1  is an elevation view of a drilling system that includes devices for determining whirl of the drill string and/or the drill bit during drilling of a wellbore; 
         FIG. 2  is a flow diagram showing a method for determining whirl, according to one embodiment of the disclosure; 
         FIG. 3A  is a graph showing acceleration a x (t) along the y-axis versus time t[s] along the x-axis of a rotating tool over a measurement window; 
         FIG. 3B  is a graph showing acceleration a y (t) along the y-axis versus time t[s] along the x-axis of a rotating tool over a measurement window; 
         FIG. 3C  shows a graph of lateral acceleration obtained from the acceleration a x (t) shown in  FIG. 3A  and acceleration a y (t) shown in  FIG. 3B ; 
         FIG. 4A  is a graph showing the magnitude of acceleration a x (f) of the tool in the frequency domain along the y-axis and the frequency f[Hz] along the x-axis; 
         FIG. 4B  is a graph showing magnitude of acceleration a y (f) of the tool in the frequency domain along the y-axis and the frequency f[Hz] along the x-axis; and 
         FIG. 5  is an exemplary graph showing the relationship of the phase angle and time that may be used for calculating whirl rate of a rotating tool. 
     
    
    
     DESCRIPTION OF THE EMBODIMENTS 
       FIG. 1  is a schematic diagram of an exemplary drilling system  100  that includes a drill string  120  having a drilling assembly or a bottomhole assembly  190  attached to its bottom end. Drill string  120  is shown conveyed in a borehole  126  formed in a formation  195 . The drilling system  100  includes a conventional derrick  111  erected on a platform or floor  112  that supports a rotary table  114  that is rotated by a prime mover, such as an electric motor (not shown), at a desired rotational speed. A tubing (such as jointed drill pipe)  122 , having the drilling assembly  190  attached at its bottom end, extends from the surface to the bottom  151  of the borehole  126 . A drill bit  150 , attached to the drilling assembly  190 , disintegrates the geological formation  195 . The drill string  120  is coupled to a draw works  130  via a Kelly joint  121 , swivel  128  and line  129  through a pulley. Draw works  130  is operated to control the weight on bit (“WOB”). The drill string  120  may be rotated by a top drive  114   a  rather than the prime mover and the rotary table  114 . 
     To drill the wellbore  126 , a suitable drilling fluid  131  (also referred to as the “mud”) from a source  132  thereof, such as a mud pit, is circulated under pressure through the drill string  120  by a mud pump  134 . The drilling fluid  131  passes from the mud pump  134  into the drill string  120  via a desurger  136  and the fluid line  138 . The drilling fluid  131   a  discharges at the borehole bottom  151  through openings in the drill bit  150 . The returning drilling fluid  131   b  circulates uphole through the annular space or annulus  127  between the drill string  120  and the borehole  126  and returns to the mud pit  132  via a return line  135  and a screen  185  that removes the drill cuttings from the returning drilling fluid  131   b . A sensor S 1  in line  138  provides information about the fluid flow rate of the fluid  131 . Surface torque sensor S 2  and a sensor S 3  associated with the drill string  120  provide information about the torque and the rotational speed of the drill string  120 . Rate of penetration of the drill string  120  may be determined from sensor S 5 , while the sensor S 6  may provide the hook load of the drill string  120 . 
     In some applications, the drill bit  150  is rotated by rotating the drill pipe  122 . However, in other applications, a downhole motor  155  (mud motor) disposed in the drilling assembly  190  rotates the drill bit  150  alone or in addition to the drill string rotation. A surface control unit or controller  140  receives: signals from the downhole sensors and devices via a sensor  143  placed in the fluid line  138 ; and signals from sensors S 1 -S 6  and other sensors used in the system  100  and processes such signals according to programmed instructions provided to the surface control unit  140 . The surface control unit  140  displays desired drilling parameters and other information on a display/monitor  141  for the operator. The surface control unit  140  may be a computer-based unit that may include a processor  142  (such as a microprocessor), a storage device  144 , such as a solid-state memory, tape or hard disc, and one or more computer programs  146  in the storage device  144  that are accessible to the processor  142  for executing instructions contained in such programs. The surface control unit  140  may further communicate with a remote control unit  148 . The surface control unit  140  may process data relating to the drilling operations, data from the sensors and devices on the surface, data received from downhole devices and may control one or more operations drilling operations. 
     The drilling assembly  190  may also contain formation evaluation sensors or devices (also referred to as measurement-while-drilling (MWD) or logging-while-drilling (LWD) sensors) for providing various properties of interest, such as resistivity, density, porosity, permeability, acoustic properties, nuclear-magnetic resonance properties, corrosive properties of the fluids or the formation, salt or saline content, and other selected properties of the formation  195  surrounding the drilling assembly  190 . Such sensors are generally known in the art and for convenience are collectively denoted herein by numeral  165 . The drilling assembly  190  may further include a variety of other sensors and communication devices  159  for controlling and/or determining one or more functions and properties of the drilling assembly  190  (including, but not limited to, velocity, vibration, bending moment, acceleration, oscillation, whirl, and stick-slip) and drilling operating parameters, including, but not limited to, weight-on-bit, fluid flow rate, and rotational speed of the drilling assembly. 
     Still referring to  FIG. 1 , the drill string  120  further includes a power generation device  178  configured to provide electrical power or energy, such as current, to sensors  165 , devices  159  and other devices. Power generation device  178  may be located in the drilling assembly  190  or drill string  120 . The drilling assembly  190  further includes a steering device  160  that includes steering members (also referred to a force application members)  160   a ,  160   b ,  160   c  that may be configured to independently apply force on the borehole  126  to steer the drill bit along any particular direction. A control unit  170  processes data from downhole sensors and controls operation of various downhole devices. The control unit includes a processor  172 , such as microprocessor, a data storage device  174 , such as a solid-state memory and programs  176  stored in the data storage device  174  and accessible to the processor  172 . A suitable telemetry unit  179  provides two-way signal and data communication between the control units  140  and  170 . 
     During drilling of the wellbore  126 , forward and/or backward whirl of the drill bit is sometimes encountered. Excessive whirl can damage the drill bit, sensors and other components in the drilling assembly  190 . The system  100  described herein includes at least two sensors that provide measurements relating to the whirl in two substantially orthogonal directions to the longitudinal axis of the drilling assembly  190 . In one embodiment, sensors  188   a  and  188   b  are placed in the drill bit  150 . In another embodiment sensors  188   a ′ and  188   b ′ are placed in the drilling assembly  190  and or at another suitable location in the drill string  120 . The suitable sensors include sensors that provide measurements for acceleration, bending moment, velocity and/or displacement. For ease of explanation, the methods of determining whirl according to this disclosure herein are described in reference to exemplary  FIGS. 2-5  using acceleration measurements obtained from sensors  188   a ,  188   b  or  188   a ′ and  188   b′.    
       FIG. 2  is a flow diagram showing a method  200  for determining the presence and magnitude (rate) of whirl, according to one embodiment of the disclosure. The exemplary method  200  is described utilizing acceleration measurement made in two orthogonal directions a x (t) and a y (t) to the tool longitudinal axis obtained from the sensors in the tool or derived from prior measurement data ( 205 ). In one aspect, the measurement signals may include original measurements (also referred to as the raw data) or partially processed raw data (for example, filtered version of original measurements). In one aspect, these measurements may be taken over selected time windows, such as five seconds or another suitable duration. In aspects, the time history of the measured parameter may be sub-divided into multiple signals of smaller duration for more accurate identification of whirl in cases where whirl may exist for a smaller duration than the duration of the measurement window. 
     In this particular example, the acceleration measurements a x (t) and a y (t) are radial and tangential accelerations and are respectively identified at boxes  210   a  and  210   b . A value or quantity  222  of a parameter  220 , such as lateral acceleration, is calculated from a x (t) and a y (t). It is known that high lateral acceleration may be an indication of whirl. If the value  222  of the lateral acceleration  220  is below a threshold level or within a selected tolerance, such as identified at the decision box  224  and box  226 , the process for determining whirl may be stopped (Box  227 ), signifying absence of whirl. If the value  222  of the lateral acceleration  220  exceeds the threshold or is outside the tolerance level (Box  228 ), signifying that whirl may be present. In such a case, the whirl in time domain is calculated. In one aspect, the whirl rate may be computed using a phase unwrapping method using the relationship:
 
whirl rate=rotational speed of the tool−slope of the phase angle
 
       FIG. 5  shows a graph  500  illustrating an exemplary method of obtaining time domain whirl rate from acceleration a x (t) and a y (t) for a known rotational speed of a tool. The phase angle (theta) may be calculated as: theta=arctan (a y (t)/a x (t)). In  FIG. 5 , the phase angle is plotted along the vertical axis  512  and the time t[s] along the horizontal axis  514 . Line  520  is the fit line over the phase angle data  530 . Slope  540  of the phase angle and the rotational speed of the tool are related as: slope=rotational speed−whirl rate. Therefore the whirl rate may be computed as: whirl rate=slope−rotational speed. Since the rotational speed of the tool at any given time is known and the slope  540  can be computed from the a x (t) and a y (t) as described above, the whirl rate in time domain may be computed at any time during drilling of a wellbore. 
     Once it is determined that the lateral acceleration exceeds the threshold (Box  228 , the method  200  determines the a x (t) and a y (t) accelerations in the frequency domain.  FIG. 3A  is a graph  310  showing exemplary acceleration a x (t) measurements  320  in the time domain, wherein the vertical axis  312  represents the magnitude of the acceleration and the horizontal axis  314  represents time over which the acceleration measurements are made. In the example of  FIG. 3A , the time window is five (5) seconds and the predominant acceleration occurs in the two to three second window.  FIG. 3B  is a graph  330  showing an exemplary acceleration a y (t) measurements  340  in the time domain, wherein the vertical axis  332  represents the magnitude of the tangential acceleration and the horizontal axis  334  represents time over which the measurements are made. The time window for the measurements  340  is five (5) seconds and the predominant tangential acceleration occurs in the window between two and three seconds. The magnitude of the accelerations  312  and  332  may be dimensional, have units, such as “g” or “g 2 ” or it may be dimensionless, such as decibels.  FIG. 3C  shows a graph  360  of lateral acceleration  370  computed from the acceleration a x (t) shown in  FIG. 3A  and acceleration a y (t) shown in  FIG. 3B . In one aspect, the lateral acceleration  370  may be the vector sum of a x (t) and a y (t). The magnitude of the lateral acceleration  370  in the time domain a lat (t)  360  is shown along the vertical axis  362  and the time is shown along the horizontal axis  364 . The lateral acceleration is shown in a selected window of one second. 
       FIG. 4A  is a graph  410  showing the acceleration a x (f) of the tool in the frequency domain, which may be obtained using any suitable technique, including Fast Fourier Transform.  FIG. 4A  shows the magnitude of the acceleration a x (f) along the vertical axis  412  and the frequency f[Hz] along the horizontal axis  414 .  FIG. 4A  shows that the dominant frequency component or peak acceleration  420  occurs at a frequency of about 31.2 Hz.  FIG. 4B  is a graph  430  showing acceleration a y (f) of the tool in the frequency domain, which may be obtained using any suitable technique, including Fast Fourier transform.  FIG. 4B  shows the magnitude of the acceleration a y (f) along the vertical axis  432  and the frequency f[Hz] along the horizontal axis  434 .  FIG. 4B  shows that the dominant frequency component or peak acceleration  440  occurs at a frequency of about 31.2 Hz. Although the particular examples of  FIGS. 4A and 4B  show one peak for the acceleration, in various cases, there may be two or more peaks. 
     Referring back to  FIG. 2 , computing the accelerations a x (f) and a y (f) in the frequency domain are respectively shown in boxes  252   a  and  252   b . From a x (f) and a y (f), the dominant frequency for each is determined (Box  252 ) as described in reference to  FIGS. 4A and 4B . If there is no dominant frequency (Box  255 ), the process stops (Box  257 ), concluding absence of whirl. The method then determines whether the difference between dominant frequencies of a x (f) and a y (f) is within a tolerance (Box  254 ). If no, the process stops (Box  256 ), concluding absence of whirl. If yes (Box  258 ), the method computes the whirl rate in the frequency domain (Box  260 ). The method then compares magnitudes of the computed time domain whirl and the frequency domain whirl (Box  270 ) and if they are outside a tolerance (Box  272 ), the process stops (Box  274 ), confirming or concluding absence of whirl. If yes (Box  276 ), the method concludes the presence of whirl and quantifies the whirl rate (Box  280 ). Thus, the method determines when or whether the whirl is present from the measurements of a parameter relating to whirl (acceleration, for example) relating to whirl in at least two directions and quantifies the whirl rate. 
     Thus, in general, the method in one embodiment determines whether the lateral acceleration is elevated, and if so, whether the accelerations in two orthogonal or substantially orthogonal directions in the frequency domain have relatively focused peaks and, if so, then whether the calculated whirls in the time domain and the frequency domain match or are consistent with each other. Such a method provides a verified existence of whirl and its magnitude. This is because the lateral accelerations a lat  during well-developed backward whirl events are high due to higher frequency of vibrations and significant impacts. The backward whirl rate can be reliably calculated. The lateral acceleration in general depends upon several factors, such as formation type, drilling assembly configuration wellbore inclination, drilling parameters, etc. Therefore, the threshold for the lateral acceleration may be chosen based on the drilling assembly configuration and the formation through which the drilling is performed. The above method may be implemented using the downhole control unit  190  ( FIG. 1 ) and/or the surface control unit  140  ( FIG. 1 ) using programmed instructions  176  ( FIG. 1 ) for in-situ determination of the whirl rate. 
     As noted above, in some cases, the accelerations may exhibit two or more dominant frequencies (i.e., peaks). For example, one peak may occur at a lower frequency, for example 3 Hz, and another at a higher frequency, such as 40 Hz. If the criteria described above are met, the method analyzes the two or more peaks in the manner described above and determines the number of whirl events present and their corresponding frequencies and magnitudes. 
     In general, the disclosure describes an improved method and algorithm for detection of backward whirl of the drill bit and/or the drilling assembly from downhole measurements of acceleration and/or bending moments. In one aspect, a method according to a particular embodiment involves the use of three different measures: (1) acceleration magnitudes, (2) dominant frequencies in the spectral data, and (3) a whirl rate calculated from the accelerations. Specifically, when the acceleration magnitude exceeds a threshold value, and the spectral and calculated frequencies match or substantially match each other, and the calculated frequency indicates backward precession, whirl is indicated. If one of these three measures is not satisfied, then backward whirl is not indicated. In aspects, this method can provide relatively accurate estimates of the whirl rate. 
     In other aspects, when utilizing measured lateral accelerations, the method assesses several specified criteria for detecting backward whirl. In one embodiment: (1) A threshold value of the severity of lateral accelerations is defined. The threshold may be indicated by a root mean square value or other measures of severity. The threshold may depend on several factors, including, but not limited to, the configuration and the size of the drilling assembly, formation being or to be drilled, previous data from the offsets wells etc.; (2) A time window of size smaller than the measurement window, at least encompassing events of high lateral accelerations, if any, is identified within the measured signal. If the severity of lateral vibration in the chosen window (for example computed as the root mean square value) is greater than a pre-defined threshold value, the calculation proceeds to step 3; (3) The whirl rate is calculated for the chosen time window using any of the existing techniques, such as phase-unwrapping method; (4) A dominant frequency is identified in the frequency spectrum for each of the orthogonal components of lateral accelerations (denoted by a x  and a y ). The dominant frequencies may be identified by creating bins of suitable frequency range and calculating magnitude of signal within each bin; (5) The identified dominant frequencies in the a x (f) and a y (f) are compared with each other; (6) If they agree within a tolerance, an average value of the identified dominant frequencies is corroborated with the calculated whirl rate and the measured average rotational speed of the drill bit or the drill string, as the case may be; (7) if a selected relationship between the three variables is satisfied (i.e. is within a tolerance level), then backward whirl is deemed present and the calculated whirl rate is reported as the backward whirl rate; and (8) if any of the criteria mentioned above is not satisfied, then the measurement data do not indicate the presence of backward whirl. 
     In another aspect, the lateral accelerations may be subjected to filtering to remove effects of events that are unrelated to whirl but that may deteriorate the accuracy of the calculations of whirl rate. A process similar to the steps described above for lateral accelerations may then be followed for determining the presence of backward whirl, its magnitude and frequency. A computer program to implement the methods described herein may be utilized in a downhole device, such as processor  172  ( FIG. 1 ), using the measurements from the sensors, such as sensors  188   a ,  188   b  and  188   a ′ and  188   b ′ ( FIG. 1 ). Alternatively, the methods described herein may be implemented during post-processing of the measurements from downhole sensors. Such programs may also be utilized with computed data that may be generated by an analytical scheme, a numerical scheme or a combination thereof. Such methods may also be used as a simulation tool for design and decision making (pre-well analysis) or after the fact (post-well analysis) to characterize the behavior and performance of a well. 
     While the foregoing disclosure is directed to the certain exemplary embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations within the scope and spirit of the appended claims be embraced by the foregoing disclosure.