GB2275283A - Detection of bit whirl - Google Patents

Abstract

The present invention is directed to a method and apparatus for determining when a drillstring in a wellbore is susceptible to bit whirl. When characterized as a method, the method steps include (1) monitoring a vibration characteristic of the drillstring during drilling operations, and (2) monitoring the frequency spectrum of the vibration characteristics for signals which are indicative of bit whirl.

Description

DETECTION OF BIT WHIRL The present invention relates in general to techniques for drilling oil and gas wellbores, and in particular to techniques for detecting and preventing undesirable bit whirling of a drill bit in a wellbore during drilling operations.

Recently, the oil and gas industry has become aware of the detrimental effect of "bit whirl" on the performance and longevity of earth boring bits, and in particular on the performance and longevity of polycrystalline-diamond-compact (PDC) rockbits. Considered broadly, "bit whirl" occurs when a earth boring bit experiences some motion of its geometric center about the axis of the borehole. Still more particularly, "bit whirl" is considered to occur when the instantaneous center of rotation of the earth boring bit moves about the bit face as the bit rotates; in other words, the center of rotation is not stable, and instead changes in position over time. Such a motion of an earth boring bit may be periodic or nonperiodic (chaotic).When the center of bit rotation and the axis of the borehole coincide (and thus the instantaneous center of rotation is substantially stable), the earth boring bit can be considered to be rotating "smoothly". However, when the center of bit rotation and the axis of the borehole do not coincide (and implicitly the instantaneous center of rotation moves about the bit face as it rotates) the earth boring bit can be considered to be in a "whirling" condition.

This whirling condition is considered to be highly undesirable, and can lead to cutter destruction in a PDC earth boring bit, and certainly represents an inefficient drilling condition, which results in a higher cost per wellbore foot As the industry has shifted toward the use of PDC bits, in place of three-cone rolling cutter rock bits, the problem of undesirable bit whirl has drawn the attention of many industry experts in attempts to (1) develop a theory for understanding the causes of bit whirl, and (2) develop improvements in PDC bit design to create new types of PDC bits which are relatively unsusceptible to going into an undesirable bit whirl condition during normal drilling operations, especially since there appears to be wide agreement in the industry that conventional PDC bits and stabilizer systems are not sufficient to reliably prevent undesirable bit whirl.

Interest in bit whirl should increase in the future, particularly in view of recent theories which propose that bit whirl may be a predominant cause of (1) reduced rates of penetration for PDC bits in some drilling conditions, and (2) reduced PDC bit life. One theory holds that the cutter compacts on a whirling bit can move sideways, backward, and much faster than those on a PDC bit which is rotating smoothly, resulting in impact loads which cause the PDC cutter compacts to chip, which, in turn, accelerate wear, and adversely effect the rate of penetration which can be obtained with the PDC bit. This theory appears to be sensible, since a large portion of the bit dynamics during a bit whirling condition appear to be lateral movement around the hole.Tests have revealed that a bit whirl condition will result in a star-shaped, or basketweave cutting pattern at bottomhole, evidencing the large amount of lateral motion. Current theories submit that the high forces encountered during such lateral motions are larger than the forces which are typically encountered during "smooth" drilling operations which are free from a bit whirl condition.

It is theorized that chipping which occurs as a result of these high impacts weakens the cutter compacts and leads to premature wearing deterioration of the bit overall. The kinematics of the bit whirl condition are discussed in considerable detail in an article entitled "Bit Whirl - A New Theory of PDC Bit Failure", authored by J. F. Brett, T. M. Warren, and S. M.

Behr, published by the Society of Petroleum Engineers as SPE Paper No.

19571 in October of 1989.

The bit whirl phenomena poses particular problems for PDC bit designers, since conventional PDC bit designs are premised upon highly stable movement of the bit about the axis of the borehole, in a borehole which is at "gauge". Of course, during bit whirl, the center of rotation of the PDC bit moves as the bit rotates, causing a high number of impacts for the PDC cutter compacts: theories indicate that the number of impacts can be as much as five to thirty times more than expected during smooth drilling operations. Additionally, a whirling bit cuts an overgauged hole, allowing still further lateral movement and greater eccentricity of movement of the PDC bit.

It is believed that many controllable factors influence the propensity of a PDC bit to go into an undesirable bit whirl condition during drilling operations, including: the speed at which the drillstring is rotated, the weight placed on the bit through the drillstring, the presence or absence of stabilizers in the drillstring, the presence or absence of shock subassemblies in the drillstring, bit hydraulics and in particular the effectiveness of drilling fluid in cleaning the bottomhole, and drill bit geometry and in particular the geometric arrangement of cutter compacts on the face of the bit.

Considerable industry attention has been directed to design techniques for minimizing the propensity of a PDC bit for going into an undesirable bit whirl condition. Typically, these design techniques center around manipulation of the bit's "balance" (or conversely the bit's "imbalance"). Typically, these design efforts result in a cutter compact layout which is intended to minimize the possibility of the occurrence of bit whirl. Viewed broadly, the objective of these design efforts is to create a bit which has a net imbalance force. One fairly detailed example of one approach to developing imbalance compensated drill bits is set forth in U.S.

Patent No. 5,042,596, entitled "Imbalance Compensated Drillbit", by J. F.

Brett, and T. M. Warren, and assigned to Amoco Corporation, of Chicago, Illinois.

Undesirable bit whirling is a condition which is also found in drilling operations which employ rockbits of the type which have a plurality of rotatable cutters disposed thereon, such as the three-cone rotary rockbit.

However, bit whirl presents a much more serious problem for fixed cutter bits, such as the PDC bit, and thus has been more extensively researched and studied in the context of PDC bits than in the context of rotary rockbits.

A broad overview of the theory of bit whirl, as well as techniques for avoiding or minimizing the occurrence of bit whirl can be found in the literature, including the following articles, which are incorporated herein by reference as if fully set forth: (1) An article entitled "Development of a Whirl-Resistant Bit", authored by T.M. Warren1 J. F. Brett, and L A. Sinor, in the December 1990 issue of SPE Drilling Engineer; (2) An article entitled "Bit Whirl-A New Theory of PDC Bit Failure", authored by J. F. Brett, T. M. Warren, and S. M. Behr, in the December 1990 issue of SPE Drilling Engineer; (3) An article entitled "Case Studies of the Bending Vibration and Whirling Motion of Drill Collars", authored by J. K. Vandiver, J. W. Nicholsen, and R.

Shyu, in the December 1990 issue of SPE Drilling Engineer; (4) An article entitled 'The Genesis of Bit-lnduced Torsional Drillstring Vibrations", authored by J. F. Brett, and published by the Society of Petroleum Engineers as SPE Paper No. SPE/IADC 21943 in March of 1991; (5) An article entitled "New Mechanism in Drillstring Vibration", authored by Y. Lin and Y. Wang, and published by the Offshore Technology Conference as OTC Paper No. 6225 in May of 1990.

(6) An article entitled "The Design and Testing of Anti-Whirl Bits", authored by C. H. Cooley, P.E. Pastusek, and L A. Sinor, published by the Society of Petroleum Engineers as SPE Paper No. 24586 in October of 1992; (7) An article entitled "Directional and Stability Characteristics of Anti-Whirl Bits with Non-Axisymmetric Loading", authored by P.E. Pastusek, C. H.

Cooley, L. A. Sinor, and M. Anderson, published by the Society of Petroleum Engineers as SPE Paper No. 24614 in October of 1992; and (8) An article entitled "Bit Whirl - A New Theory of PDC Bit Failure", authored by J.F. Brett, T.M. Warren, and S.M. Behr, published by the Society of Petroleum Engineers as SPE Paper No. 19571 in October of 1989.

According to the invention there is provided a drilling method as set out in Claim 1, Claim 10, or Claim 16 or apparatus as set out in Claim 18.

In one particular embodiment of the present invention, at least one drillstring vibration characteristic is monitored with respect to time during drilling operations. At least one time-domain signal representative of the drillstring vibration characteristic is recorded and monitored.

Simultaneously, the spectral content of a drillstring vibration characteristic is determined and monitored. Bit whirl of the drill bit in the wellbore is identified, as it occurs, from substantially contemporaneous occurrence of (1) a predetermined change in the time-domain signal, preferably an elevation in the root-mean-square amplitude of vibration data, and (2) a predetermined change in the spectral content of the spectral profile in the range of the frequency spectrum bit signal bandwidth applicable to the particular drill bit, such as a change in either amplitude or location of spectral components within this particular bandwidth.

In a still more particular embodiment of the present invention, the spectral content of drillstring vibration information is displayed in a contour map which depicts spectral content changes with respect to time, preferably wherein the contour map includes a frequency axis, a time axis, and a visually-perceptible representation of amplitude of the frequency components.

Examples of the invention will now be described with reference to the accompanying drawings in which: Figure 1 is a combination of perspective, phantom, and longitudinal section view of an oil and gas well during drilling operations which is equipped with an apparatus for detecting undesirable bit whirling Figure 2 is a simplified perspective view of an alternative earth boring apparatus to that shown in Figure 1, and specifically depicts equipment which can be utilized to allow operation of a polycrystallinediamond-compact (PDC) drill bit; Figure 3 is a combination block diagram and longitudinal section view of the preferred apparatus for detecting undesirable bit whirling.

Figure 4 is a detailed view of the apparatus of Figure 3 which depicts sensor placement; Figure 5 is a block diagram view of the preferred apparatus for processing and transmitting data gathered by strain gauge sensors and accelerometers; Figure 6 is a block diagram view of the preferred data processing operations which are performed on the vibration data.

Figure 7 is a flowchart representation of the stabilizing signal processing operation which is performed upon vibration data; Figures 8a, 8b, and Sc graphically represent axial and torsional acceleration datas Figure 9 is a depiction of an exemplary strip-chart recorder presentation of data which is presented to the rig operator; and Figure 10 is a graphic representation of one technique for simultaneously displaying time-domain vibration information, as well as frequency-domain vibration information, in a manner which allows for the detection of the substantially contemporaneous occurrence of signal changes in both the time-domain signal and the frequency-domain signal; Figure 11 is a graphic representation of a spectrogram, which provides a contour map representation of vibration data, with the x-axis representative of frequency components in hertz, the y-axis representative of time in seconds1 and the gray-scale value of mapped information indicative of spectral component amplitude, with respect to a conventional gray-scale in units of 0 to 256 gray-scale units;; Figures 12a and 12b provide a graphic representation of the weight-on-bit and the surface RPM (spm) for the vibration data which is graphically depicted in Figure 11; Figure 13 is an autospectra (profile) ofthe spectrogram shown in Figure 11 at the time of 1550 seconds; Figure 14 is a vibration spectrum for a three-cone drill bit while drilling during normal "smooth" low frequency vibration; Figure 15 is a axial force spectrum prior to fatigue failure in a bottom hole assembly; Figure 16 is a spectrum of the frequency spectrum bit signature developed by a PDC bit for a sixteen-bladed PDC bit, set forth in terms of cycles per bit revolution; and Figure 17 is a graphic depiction of the root-mean-square (RMS) level of vibration data, as detected from axial strain which is represented in the lighter signal line, and torsional strain which is represented in the darker signal line, which graphically represents the bit signature frequencEband during bit whirl, with a bit whirling between a different depth, as depicted on the x-axis of the graphic representation.

In Figure 1, drilling rig 11 is depicted in phantom and includes traveling block 13 which is used to raise and lower drillstring 17 relative to derrick 15, and rotary table 19 which selectively engages drillstring 17 and rotates it within wellbore 29. Drillstring 17 includes a section of drill pipe 23 at its upper portion, and a section of drill collar 25 at its lower portion. Rock bit 27 is coupled to the lowermost end of drill collar 25, and includes cutting members for disintegrating the geologic formation at the bottom of wellbore 29. In Figure 1, a rolling cone cutter type rockbit 27 is depicted, which includes three rotatable cone members, which rotate relative to the bit body, and include a plurality of cutting teeth disposed thereon for disintegrating geologic formations. Alternatively, a fixed cutter, or "drag" bit, may be utilized.This type of cutter includes no rotating cones, and instead includes a plurality of cutting compacts, typically including a diamond portion, distributed upon the outer surface of the bit body.

Figure 2 is a perspective view of one type of fixed-cutter drill bit, which is known in the industry as a polycrystalline-diamond-compact (PDC) drill bit 12 which is coupled at the lowermost portion of drillstring 17.

A variety of special purposes are utilized in combination with PDC drill bit 12, including lower stabilizer 14, vent housing 16, motor section 18, bi-pass valve 20, and upper stabilizer 22. These components serve to allow for the selective rotation of PDC bit 12, as well as the "steering' of the entire assembly, in a conventional manner well known to those in the industry.

Hereafter, the term "rockbit 27" will be intended to comprehend the tri-cone rockbit depicted in Figure 1, as well as the PDC drill bit 12 depicted at Figure 2.

In conventional drilling operations, a stream of drilling fluid, also referred to as "mud", is directed downward through drillstring 17 and rockbit 27 to cool and lubricate rockbit 27, and carry cuttings to the surface through the annular fluid column which surrounds drillstring 17. Preferably, drilling fluid is directed from a drilling fluid reservoir (not depicted), through conduit 31, through kelly 21, into the central bore of drillstring 17. It is jetted outward through nobles provided in the body of rockbit 27.

In the preferred embodiment of the present invention, measurement subassembly 33 is coupled into drillstring 17 preferably, but not necessarily, at an upper location. In the view of Figure 1, measurement subassembly 33 is shown coupled between kelly 21 and kelly swivel 41, and is utilized to substantially continually sense a real-time property of the drilling operations, and transmit data representative of that property via microwave link 35 to microwave receiver 37, which feeds the data stream into monitoring station 39 where it is recorded, and monitored for detection of a signal change which is indicative of either (1) bit whirl, or (2) impending sticking of the drillstring before actual sticking occurs. In the preferred embodiment, measurement subassembly 33 is utilized to measure vibration in drillstring 27 at or near the surface.Drillstring 17 acts as a vibration conductor which communicates vibration signals which arise from the drillstring and/or rockbit interaction with wellbore 29. While measurement subassembly 33 is shown disposed between kelly swivel 41 and kelly 21, in alternative embodiments, it may be possible or desirable to place measurement subassembly 33 within wellbore 29.

Figures 3, 4, and 5 will now be utilized to describe the components which make up measurement subassembly 33. Wrth reference first to Figure 3, measurement subassembly 33 includes subassembly body 51 which is preferably formed of steel, and which defines threaded pin end 53 at its lowermost section and threaded box end 55 at its uppermost section (although any pin and box combination or orientation could be used). Measurement subassembly 33 is equipped with removable battery pack 57 which powers all the electrical components contained within subassembly 33.Measurement subassembly 33 further includes signal processing electronics 59 which receive data signals and communicate them to microwave transmitting antennae 61 which selectively radiates microwave communications encoded with a data stream representative of the - vibration which is sensed in measurement subassembly 33.

Measurement subassembly 33 is further equipped with central bore 63 which extends from threaded box end 55 to threaded pin end 53, and which serves to allow for the communication of drilling fluid downward from kelly swivel 41 (not depicted in this figure, but depicted in Figure 1) through kelly 21 to drillstring 17.

With reference now to Figure 4, in the preferred embodiment of the present invention, measurement subassembly 33 is equipped with the plurality of sensors capable of substantially continuously sensing a real-time property of the drilling operations. In the preferred embodiment of the present invention, the real time property of drilling operations which is measured is vibration. In the preferred embodiment, four strain gauge sensors 65, 67, 69, 71 are provided along with four accelerometers 73, 75, 77, 79. Preferably, two of the strain gauge sensors 65, 69 are oriented to detect axial strain within subassembly body 51 which is indicative of the drillstring 17 and/or rockbit 27 interaction with wellbore 29.Additionally, strain gauges 67, 71 are oriented to detect torsional strain within subassembly body 51 which is likewise indicative of the drillstring 17 and/or rockbit 27 interaction with wellbore 29. In addition, accelerometers 73 75, 77, 79, are also located within measurement subassembly 33 for detection of acceleration of subassembly body 51 in response to the interaction between drillstring 17 and/or rockbit 27 with wellbore 29. In the preferred embodiment of the present invention, accelerometers 73, 77 are provided for measurement of torsional acceleration of subassembly body 51. Also, in the preferred embodiment of the present invention, accelerometers 75, 79 are provided for detection of axial acceleration of subassembly body 51 of measurement subassembly 33.

In the preferred embodiment of the present invention, Model No. S/A9P-1O0-300, semiconductor-type strain gauges manufactured by Kulite of Lenoie, New Jersey, are arranged in an electrical wheatstone bridge configuration to allow measurement of both the axial and torsional strain in subassembly body 51. Also, in the preferred embodiment of the present invention, Model No. ESAXT-259 and ESAXT-2509 accelerometers manufactured by Entran of Fairfield, New Jersey, are provided for measurement of the axial and torsional acceleration of subassembly body 51.

The signal processing operations which are performed upon the data sensed by strain gauges 65, 67, 69, 71 and accelerometers 73, 75, 77, 79 are depicted in block diagram form in Figure 5. As is shown therein, the outputs of axial strain gauges 65, 69 are directed to amplifier 89. The outputs of axial accelerometers 75, 79 are directed to summing amplifier 83.

The outputs of torsional accelerometer 73, 77 are directed to summing amplifier 85. The outputs of torsional strain gauges 67, 71 are directed to amplifier 95. Summing amplifiers 83, 85 operate to simultaneously add and amplify the output signals of the various sensors. The outputs of summing amplifiers 83, 85, are directed to amplifiers 91, 93, respectively, for further amplification. In the preferred embodiment of the present invention, the vibration data from the sensors is sampled at a rate of 2,083 samples per second per channel. Also, preferably, anti-aliasing filters are used prior to sampling to ensure a non-aliased measurement in a 500 Hertz bandwidth (from 0 Hertz to 500 Hertz). The outputs of amplifiers 89, 91, 93, 95, are directed to multiplexer 105 which multiplexes the sensor data and transfers it to digitizer 103.Data buffer 107 then stores the data for use by microwave transmitter 109 which energizes omni-directional microwave antenna 61 for transmission of a data stream in microwave form from measurement subassembly 33 to microwave receiver 37 at monitoring station 39, for further processing of the data stream. In the present invention, data is transmitted over the microwave linkage at a rate of 200 kilobits per second, so a large amount of data is provided for analysis.

In the preferred embodiment of the present invention, the microwave communication system is preferably a Model No. TBT-50-25TL transmitter and a Model No. TBR-200-TL receiver manufactured by B.M.S.

of San Diego, Califomia. Also, in the preferred embodiment of the present invention, summing amplifiers 83, 85, are Model No. D51762510-C summing amplifiers manufactured by Exlog, Inc., of Houston, Texas; amplifiers 89, 91, 93, 95 are Model No.760PC2 amplifiers manufactured by Metraplex of Frederick, Maryland; digitizer 103 is a Model No. 760AD1 analog-to-digital converter manufactured by Metraplex of Frederick, Maryland; and the multiplexer 105 is a Model No. 760AD1 multiplexer manufactured by Metraplex of Frederick, Maryland.

Figure 6 is a block diagram and pictorial representation of the data processing operations performed upon the microwave-transmitted data stream. As is shown, receiver 37 receives the microwave transmission, and directs it in serial form to decomutator 111 which perform a decoding function. The data is split in parallel and then directed to (1) recording device 113 for recording and selective playback, and (2) to high data rate processing system 115 which performs data processing operations on the data stream in real-time. Recording device 113 is used to store all data for later analysis and research. High data rate processing system 115 is used for real-time data analysis. Data is routed into high data rate processing system 115 at raw time data processing block 117.The data stream is simultaneously provided to frequency domain operation blocks 119, 121, 123, as well as a time-domain stabilizing signal processing operation block 125. Frequency domain operation block 119 performs spectral analysis on vibration which is in the range of 0 to 150 Hertz. Frequency domain operation block 121 performs spectral analysis of vibration which is in the frequency range of 0 to 50 Hertz. Frequency domain operation block 123 performs spectral analysis on vibration which has a frequency in the range of 0 to 1.25 Hertz.

Bit signature operation 127 operates on the output of frequency-domain operation block 119, while vibration analysis operation 127 operates on the output of frequency-domain operation blocks 121,123.

Bit signature operation 127 is an operation which identifies the spectral profile of vibration data which is characteristic of interaction of drillstring 17 and/or of rockbit 27 with the geologic formation, during normal operating conditions. This signature can be compared over time to detect changes in the signal which indicate deterioration or malfunctioning of rockbit 27.

Vibration analysis operation 129 performs vibration analysis which is necessary for the Drillbyte Wellsite Information Management System of Exlog, Inc., a division of Baker Hughes Incorporated, of Houston, Texas.

These operations, however, are not necessary for the detection of impending pipe sticking, which is the subject of the present invention.

The output of stabilizing signal processing operation 125, bit signature operation 127, and vibration analysis operation 129 are provided via bus 131 to a graphics and data interpretation program which is run on either a PC-based or Unix system, and which is visually represented by computing unit 133, as well as the Drillbyte Well Site Information Management System of Exlog, Inc., a division of Baker Hughes Incorporated of Houston, Texas, which is visually represented by computing unit 135.

Computing unit 135 also receives data from conventional sensors 137, through slow data rate processing system 139, in a conventional manner.

The data provided by conventional surface sensors includes an indication of the kelly height, the rate of penetration, and the weight on bit, but could also include the rate of rotation of drillstring 17 in revolutions per minute, torque of drillstring 17, and pump pressure in strokes per minute.

The operation of stabilizing signal processing operation 125 is depicted in flowchart form in Figure 7. In the preferred embodiment of the present invention, the operations depicted in Figure 7 are performed by software in a conventional data processing system; however, it may be possible to perform all these operations utilizing conventional electrical and electronic components. The objective of the stabilizing signal processing operation is to eliminate the influence of noise on the data stream, and render the data more "readable". Preferably, this includes normalizing the data to make all strain and accelerometer data positive. The process starts at software block 141, and continues in software block 143, wherein accelerometer or strain gage output data is received. Next, in accordance with software block 145, the data is packetized preferably in five second intervals.In the preferred embodiment, amplitudes for samples in each five second interval are averaged. Then, in accordance with software block 147, the data is subjected to a stabilizing and/or normalizing operation. In the preferred embodiment of the present invention, a root-mean-square (RMS) operation is performed on the data. Those skilled in the art will appreciate that the root-mean-square operation is initiated by squaring of the data, followed by averaging of the data, and concluded with taking a square root of the data. This ensures that all components of the accelerometer and/or strain gage sensors are normalized and are thus positive. Furthermore, the influence of noise components is diminished.

Next, in accordance with software block 149, the data is arranged for display with respect to a time domain, to allow comparison of the RMS amplitude of the accelerometer and/or strain gage sensor output with respect to a time axis. Preferably, the time domain provides the x-axis of any display, while the y-axis represents the RMS amplitude of the sensor output. Then, in accordance with software block 151, the data is moved to a display buffer, and in accordance with software block 153, displayed and/or printed. With reference again to Figure 6, strip chart recorder 157 is provided in the monitoring station 39 to provide a visual print out of RMS sensor output.

The root-mean-square (RMS) operation can be presented mathematically as follows: RMS Sensor Amplitude =

wherein "i" represents the series of five-second data packets, "x" represents the average sensor output for the five second interval, and "N" represents the total number of five-second data packets.

DETECTION OF DIFFERENTIAL STICKING Figure 8a, 8b, and Sc graphically depict axial acceleration with respect to time, torsional acceleration with respect to time, and a ratio of axial to torsional acceleration with respect to time, respectively, for an actual well for which vibration analysis was used to make an early detection of differential sticking using dynamic measurements from measuring subassembly 33 (of Figure 1).Each of the figures of 8a, 8b, and Sc have an x-axis which represents time, and a y-axis which represents acceleration in gravity units "g". Figure 8a shows RMS axial acceleration detected from measurement subassembly 33 in the frequency range of 0 to 500 Hertz for a period of four hours prior to the occurrence of a pressure differential sticking for a vertical offshore well. Figure 8b represents the torsional RMS acceleration with respect to time for a period of four hours prior to the occurrence of pressure differential sticking on the same vertical offshore well, for the same time period. Figure Sc depicts a ratio of RMS axial acceleration to tangential (or "torsional") acceleration with respect to time for a period of four hours prior to the occurrence of pressure differential sticking of the same vertical offshore well, for the same time periods as Figures 8a and 8b.

All acceleration data plotted in Figures 8a, 8b, and ac are sensor values which have been subjected to a root-mean-square operation (RMS) to stabilize and render the data more readable. Each data point on this curve represents a five second interval, and a low pass filter has been applied to ensure that frequencies only in the range of 0 to 500 hertz are displayed.

As is depicted in the figures, axial acceleration starts to decrease in amplitude approximately two-hundred minutes before the drillstring becomes stuck, and reaches a minimum my minutes prior to the drillstring becoming stuck. As is also evident from the figures, the levels of torsional acceleration increased dramatically one hundred and twenty minutes prior to the drillstring becoming stuck. These features are both attributed to the increase in friction between the bottom hole assembly and the wellbore as the pipe becomes stuck.In the case of axial acceleration, the increase in friction presumably results in an increase of attenuation of detectable axial vibration originating from below the stuck point. in the case of torsional acceleration, the increase in friction results in increased dynamics as the pipe alternately "sticks" and then "frees" against the wellbore wall. Figure 8c shows a ratio of the axial acceleration to the torsional acceleration, plotted with respect to time. Note that this ratio reaches a minimum immediately prior to sticking of the pipe. Also note the high levels of torsional acceleration which occur immediately prior to the connection at one hundred and fifty minutes, and prior to the pipe becoming stuck at two hundred and fifty minutes. There is an associated increase in axial acceleration at these points, although the ratio measurements decrease, as is shown in Figure 8c.

With reference now to Figures 8a, 8b, and 8c, the vibration attributes which are believed to be indicative, or potentially indicative, of impending pipe stickage are: (1) a gradual decrease in the RMS amplitude of axial vibration, as determined from either axial acceleration or axial strain measurements, for a prolonged period prior to actual sticking of the pipe in the wellbore, such as during the time period identified by span 171 in Figure Ba; (2) an increase in the RMS amplitude of torsional vibration, as detected through use of either torsional acceleration or torsional strain measurements, for a prolonged period prior to the actual occurrence of sticking of the pipe in the wellbore, such as time span 173 in Figure 8b; or (3) a decrease in the ratio or the RMS values of axial to tangential vibration, as detected through either use of accelerometers or strain gauges, for a prolonged period prior to the occurrence of actual sticking of the drillstring in the wellbore, such as time span 175 in Figure 8c.

In the preferred embodiment of the present invention, information pertaining to the RMS amplitude of either axial or torsional vibration is displayed on either a video display or a strip chart recorder to allow the operator to compare vibration amplitudes over a selected time interval. Preferably, the comparison is made visually, to allow a high degree of operator judgment in analyzing the data. Preferably, the vibration information is displayed along with other information pertaining to drilling conditions to allow the operator to see the interrelationship between controllable drilling conditions.

Figure 9 is an example of one strip chart presentation of a variety of drilling conditions, variables, and parameters, displayed on a common time axis (the Y-axis). Signal 191 is a signal which is representative of the rate of penetration of the drillbit 27 in the wellbore.

Signal 193 is a signal which is representative of the kelly height, which provides an indication of the depth of the wellbore. Signal 195 provides a visual representation of the RMS amplitude of torsional strain data, while signal 197 provides a visual representation of the RMS amplitude of torsional acceleration. Signal 199 provides a visual representation of the RMS amplitude of axial strain, while signal 201 provides a visual representation of the RMS amplitude of axial acceleration. Signal 203 provides a visual representation of the weight-on-bit. Signal 205 is a static hook load channel, which is obtained from a static strain gauge (not depicted) in the subassembly. Signal 207 is a visual representation of the torque in the drillstring. Signal 209 is a visual representation of the speed of rotation of the drillstring in revolutions per minute.This type of display allows the operator to monitor conventional drilling conditions, such as the rate of penetration, the weight on the bit, and the rotary speed of the string, while also monitoring vibration data.

Changes in the vibration data signals will alert the operator that sticking may be about to occur, so modifications must be made in one or more drilling conditions in order to prevent the drillstring from becoming stuck. The operator may take remedial actions which include altering one or more of the drilling fluid properties, such as fluid type, fluid density, fluid viscosity, and fluid flow rates, as well as particle content. Additionally, the operator may add lubricants to the drilling fluid to minimize the possibility of differential sticking. Also, the operator may alter the frequency and amount of drillstring movement, both axial and rotary movement, to minimize the opportunity for the occurrence of differential sticking.

BIT WHIRL DETECTION In the present invention, undesirable bit whirl of a drill bit (either a PDC drill bit or a tri-cone rotary drill bit) may be detected by monitoring of drillstring 17 vibration in an uphole location, preferably on the rig floor, and in the particular embodiment of the present invention above the kelly 21. Whiie the particular embodiment is shown and depicted herein, the present invention may utilize any type of measurement of vibration obtained at the surface or downhole, including any of the following: (1) axial acceleration, dynamic axial force, tangential acceleration, or dynamic torsional moment. Either accelerometers or strain gauges may be utilized to detect such vibration.In the preferred embodiment of the present invention, such vibration data is particularly monitored in a frequency range which is likely to encompass the "frequency spectrum bit signal band" or "frequency spectrum bit signal bandwidth". The "bit signal band" or "bit signal bandwidth" are terms which signify a range of frequencies which relate directly to the cutting action of a bit. This frequency range is a function of the bit design geometry, as well as the speed with which the bit is rotating. For example, in the case of a bladed PDC bit, with a structure comprising of sixteen discrete blades, rotation of the bit at sixty revolutions per minute will result in a bit signal band (or bandwidth) which is centered around a frequency of sixteen hertz. Focusing in on a frequency or frequency range which is directly attributable to (1) cutter design and (2) speed of rotation of the drill bit ensures that vibration data which is most relevant to the particular drill bit is being monitored, while vibration data which is not nearly as relevant is not monitored.

In the present invention there are three specific mechanisms are proposed for the accurate and efficient detection of undersirable bit whirl, including: (1) the filtering of vibration data to ensure that vibration data only in the range of the bit signal band/bandwidth is monitored and subjected to a spectral analysis; with respect to Figure 6, the operation represented by block 119 is representative of a Fast Fourier Transform (FFT), which is accomplished by conventional software operations, upon vibration data which is the range of 0 to 150 hertz. As is shown by operation block 127, the bit signature is developed from this information.

Additionally, operation block 121 represents the application of a Fast Fourier Transform (FIT) to vibration data in a range of 0 to 50 hertz. Likewise, operation block 123 is representational of the application of a Fast Fourier Transform to vibration data in the range of 0 to 1.25 hertz.The operation blocks 121, 123 may be used for other types of vibration analysis, and specifically types of vibration analysis which are utilized in the Drillbyte Wellsite Information Management System of Exlog, Inc. (b) One specific embodiment of the present invention, vibration data, such as the raw rootmean-square (RMS) vibration level, such as depicted in Figure 10a, may be utilized in combination with spectral analysis data, such as that depicted in Figures 10b through 1 Oc, to determine bit whirl, as it occurs. Preferably, software, or a human operator, monitors the time-domain signal as well as the frequency-domain signal to determine the substantially concurrent occurrence of changes in both the time-domain signal and the frequencydomain signal.The spectrogram of Figure 10b, lOc, and lOd include an x-axis which is representative of frequency, a y-axis which is representative of time, and a signal disposed thereon which indicates the frequency location of a predominant frequency component of the vibration data, such as that depicted in Figure 10c. As is shown in Figures 10b, 10c, and lOd, the signal band is determined by the frequency range from F, to Fb.

Movement of the dominant frequency component out of the signal band is indicative of fully developed bit whirl. Figures 1 0e, 10f, and 109 depict autospectra which correspond respectively to the depictions of Figure 10b, 10c, and 10d. In the preferred embodiment of the present invention, this information should be displayed, as is shown, to provide a common time axis to allow for the simultaneous monitoring of time-domain vibration signals as well as frequency-domain vibration signals.

As shown, excitation of the drillstring in the vicinity of a natural frequency may lead to the development of an anomalously high amplitude resonance. This has long been recognized and, for example, the coincidence of the three times bit RPM signal and the first axial node of many drillstrings has been noted. This is the underlying assumption for many drillstring dynamic models in which excitations at multiples of the bit rotary speed are applied in harmonic analysis in order to predict RPM operating windows (RPM ranges for which the predicted vibration levels are low).However, drillstring excitations may not occur at integer multiples of the RPM; modeling boundary conditions may not be correct; the role of formations-or formation changes-appears critical in developing high amplitude excitations; and lateral natural frequencies are often so closely spaced as to apparently close all operating windows. Therefore avoidance of damaging resonance depends on real-time monitoring.

Hereinafter, we use the term "resonance" in referring only to potentially damaging, anomalously high amplitude resonances, rather than low level resonances. Our premise is that anomalously broad and high spectral peaks must coincide with a natural frequency of the system. The two are empirically distinguished in the field by plotting spectral amplitudes on a linear scale rather than the more conventional logarithmic decibel scale; the high amplitude resonances are readily visible on the linear scale while the noncritical low amplitude resonances are not.

Figure 11 depicts data from a vertical onshore well at approximately 12,000 ft. (3660 m), drilling with a 12.25 in (311 mm) roller cone bit, and illustrates how small changes in WOB and RPM can result in a resonance. The spectrogram of the data is shown in Figures 11, and WOB and surface RPM in Figures 12a and 12b. A mud motor was in use turning at approximately 96 RPM (1.6 Hz), resulting in a bit rotary speed of 135 to 141 RPM (2.25 to 2.35 Hz) through the data set. In the figure the surface rotary speed, bit rotary speed and pump rate traces are clearly identified, as are the resonances (Figure 13 shows a detailed spectrum 1550 seconds into the data set). Note the difference in character of the traces between resonances and excitations. This difference is used in rapidly identifying those features in real time.

A low amplitude resonance can be seen between 6.0 and 7.0 Hz with WOB at 32,000 Ibs (142kN) and a rotary table speed of 44, and we will refer to this as the "6 Hz resonance" in the following discussion. This resonance grows markedly in both amplitude and width when the WOB changes to 43,000 Ibs (191kN) and the rotary table speed to 41. In resonance analysis it is more important to monitor the area under the amplitude curve rather than the peak value of the resonance. Since the area under the square of the spectral amplitude curve (also called the power spectra) is proportional to the variance of the signal, the increased width and height of the 6 Hz resonance represents a significant increase in the peak-to-peak amplitude of the resonant vibration.

From a correlation with the excitation frequencies it would appear that the 6 Hz resonance is excited by the three-times bit harmonic.

Note that another resonance is present at approximately 8.5 Hz. An afterthe-event analysis attempted to identify the mode of the resonances using a commercially available software package. It was concluded that the 8.5 Hz resonance was probably an axial resonance (i.e., it occurred in the vicinity of an axial natural frequency). There were no well defined axial or torsional natural frequencies in the vicinity of the 6 Hz resonance. There was, however, a "band" of closeiy spaced lateral natural frequencies, and from this it was concluded that the 6 Hz resonance was possibly a lateral resonance. This illustrates a potential use of integrated modeling with realtime data. Eliminating drillstring resonances in the field is usually straightforward. The rotary speed and, if necessary, the WOB, are changed to a new operating window. The drill rate is also monitored to ensure that the new conditions produce an acceptable rate of penetration.

Figure 14 illustrates the typical relationship between the one, two and three times bit RPM excitation peaks while drilling with a roller cone blt: the one times peak is generally dominant; the two times peak is less than the one times; the three times is often the smallest of the three, but may be significant when a three times excitation is present, possibly due to a trilobed pattern created by the bit. A special amplitude signature such as this is referred to as "normal" for a roller cone bit.

Figure 15 is a spectrum taken prior to a bending fatigue failure in the box end of a 9.25 in. (235 mm) drill collar. The data is from a depth of approximately 4500 ft. (1370 m) while drilling with a 16 in. (406 mm) roller cone bit, and operating parameters of 116 RPM and 33,000 Ibs. (147 kN).

Note the presence of elevated two times and four times peaks-these are much higher than the one times RPM peak. As noted previously, any downhole lateral vibration will produce axial vibrations that are generally 1 sot, 2nd and higher harmonics of the lateral vibration. If the nature of the coupling is parametric then the 2nd harmonic is dominant. From this it would appear that the lateral vibration occurred at 2 times the bit RPM resulting in two and four times RPM peaks on the axial channel.

This is not an isolated case: this type of signature has been observed on other wells prior to the suspected development of BHA whirl and subsequent string damage or failure. Prior work has attempted to correlate the amplitudes of these measured vibrations with a nonparametric coupling mode during forward whirl.

Avoiding, or removing, high amplitude lateral vibrations can involve simply changing the operating parameters within permitted limits.

However, in several cases, once the lateral vibrations were encountered they persisted regardless of changes made by the driller. In these instances the bit must be moved off-bottom and then restarted as outlined in the next section.

Figure 16 shows the spectrum of the bit signature developed by a PDC bit on the Hughes-Christensen Drilling Machine where the measurement system was run directly above the bit. The spectra was calculated by resampling the data 720 times per revolution of the bit, using the magnetometer output to determine rotational position. This results in a plot of amplitude vs cycles per bit revolution, rather than the conventional cycles per unit time. With this type of plot the "blades" of the PDC bit generate signals with frequencies that are on integer numbers of cycles per bit revolution. There are also side-bands on each blade signal: analysis indicates that these are due to amplitude modulation of the blade frequencies by the pump pressure waves, probably caused by oscillating pump-off forces across the workface.It is important to note that the bit signature does not consist of a discrete frequency, but a band of frequencies whose center is given by the number of "working" blades on the bit. In terms of conventional time-based spectral analysis (cycles per second), the center of the bit signature of a bladed PDC bit can be estimated by: Bit Frequency = (No. of Working Blades * Bit rotary speed / 60.0 Hertz The data shown in Figure 17 is from a section of a well drilled at AMOCO's drilling research faciiity to examine the directional stability of anti-whirl PDC bits, and is from between 552.0 to 587.1 ft. TVD (168.2 to 178.9 m) while drilling with a conventional 8.5 in. (216 mm) PDC bit (as opposed to an Anti-Whirl PDC bit). WOB was 3,000 Ib. (13kN), bit RPM was 210 - a mud motor was in use - and hole inclination was 19 degrees.The RMS levels of the bandpassed dynamic torsional and axial strain signals are shown. Bandpassing was applied to focus on the frequency band associated with the bit signature.

Bit whirl was suggested by the caliper log run after drilling, which demonstrated cyclical widening ("hourglassing"). Several important points can be made: whirling started and stopped at connections; at the start of the joint the RMS values on the monitored channels showed general agreement with the caliper - the highest RMS values were encountered at points of maximum caliper departure; at the end of the joint the agreement was less clear. In general1 RMS levels within the bit signature band increased by 250-300% on strain channels while whirling; increases were approximately 200% on accelerometer channels.

The most effective manner to eliminate bit whirl (PDC or roller cone), once it has been detected, appears to be the following: (a) stop rotating and pick the bit off bottom, (b) set the bit rotary speed to one half the target on bottom rate, (c) place the bit back on bottom, slowly increasing WOB to its target value, and then (d) increase the rotary speed to the target on-bottom value. This technique results in the formation of a new bottomhole pattern and has also proved useful in eliminating high amplitude lateral vibrations.

Claims (20)

CLIMS

1. A method of drilling a wellbore utilizing a drillstring, comprising: engaging and disintegrating a geologic formation with a drill bit; substantially continuously sensing at least one drillstring vibration characteristic with respect to time during selected drilling operations for a frequency range likely to encompass a frequency spectrum bit signal bandwidth for said drill bit; recording at least one signal representative of said at least one drillstring characteristic; determining spectral content of said at least one signal for said frequency spectrum bit signal bandwidth; monitoring at least one signal characteristic of said spectral content; and identifying bit whirl of said drill bit in said wellbore, as it occurs, from said at least one signal characteristic of said spectral content.

2. A method according to Claim 1, further comprising: altering at least one drilling condition to eliminate said bit whirl.

3. A method according to Claim 1, wherein said at least one drillstring vibration characteristic with respect to time comprises at least one of (a) axial vibration, and (b) torsional vibration.

4. A method according to Claim 1, further comprising: providing a tubular subassembly with at least one vibration sensor disposed therein; placing said tubular subassembly in said drillstring at an upper location; and wherein said step of substantially continuously sensing comprises: sensing a drillstring vibration characteristic of said drillstring during selected drilling operations with said at least one vibration sensor which is disposed in said tubular subassembly.

5. A method according to Claim 1, further comprising: displaying said spectral content of said vibration characteristic with respect to time to allow comparison with prior spectral content of said vibration characteristic.

6. A method according to Claim 1, further comprising: providing at least one drillstring vibration characteristic sensor; placing said at least one drillstring vibration characteristic sensor in a selected position within said drillstring; sensing with said at least one drillstring vibration characteristic sensor a vibration characteristic indicative of interaction of said drill bit with said wellbore; during drilling operations, generating at least one output signal from said at least one drillstring vibration characteristic sensor; and subjecting said at least one output signal to a stabilizing signal conditioning operation.

7. A method according to Claim 1, wherein said step of sensing comprises: monitoring axial vibration of said drillstring during drilling operations.

8. A method according to Claim 1, wherein said step of sensing comprises: monitoring vibration through measurement of at least one of (1) axial acceleration and (2) torsional acceleration of said drillstring during selected drilling operations.

9. A method according to Claim 1, wherein said step of monitoring comprises: monitoring vibration through measurement of at least one of (1) axial strain and (2) torsional strain of said drillstring during drilling operations.

10. A method of drilling a wellbore utilizing a drillstring, comprising: engaging and disintegrating a geologic formation with a drill bit; substantially continuously sensing at least one drillstring vibration characteristic with respect to time during selected drilling operations; recording at least .one time-domain signal representative of said at least one drillstring characteristic; monitoring at least one signal characteristic of said at least one time-domain signal; determining spectral content of said at least one drillstring vibration characteristic; monitoring at least one signal characteristic of said spectral content; and identifying bit whirl of said drill bit in said wellbore, as it occurs, from substantially contemporaneous occurrence of (a) a predetermined change in said at least one time-domain signal, and (b) a predetermined change in said spectral content.

11. A method according to Claim 10, further comprising: in response to identification of bit whirl, altering at least one drilling condition to eliminate said bit whirl.

12. A method according to Claim 10, further comprising: providing a tubular subassembly with at least one vibration sensor disposed therein; placing said tubular subassembly in said drillstring at an upper location; and wherein said step of substantially continuously sensing includes sensing at least one drillstring vibration characteristic which is indicative of drill bit interaction with said wellbore which has been conducted upward within said wellbore through said drillstring.

13. A method according to Claim 10, further comprising: displaying (a) said at least one time-domain signal and (b)said spectral content, in a format which facilitates substantially simultaneous comparison for a common time interval.

14. A method according to Claim 10, further comprising: subjecting said at least one time-domain signal to a stabilizing signal processing operation.

15. A method according to Claim 14, wherein said stabilizing sign; processing operation comprises a root-mean-square operation.

16. A method of drilling a wellbore utilizing a drillstring, comprising: engaging and disintegrating a geologic formation with a drill bit; substantially continuously sensing at least one drillstring vibration characteristic with respect to time during selected drilling operations; recording at least one signal representative of said at least one drillstring characteristic; determining spectral content of said at least one signal; displaying said spectral content in a contour map which depicts changes with respect to time; monitoring at least one signal characteristic of said spectral content from said contour map; and identifying bit whirl of said drill bit as it occurs from changes in said at least one signal characteristic of said spectral content detected on said contour map.

17. A method of drilling according to Claim 16, wherein said contour map includes a frequency axis, a time axis, and a visually-perceptible representation of amplitude.

18. An apparatus for detecting bit whirl of a drill bit during drilling operations which involve suspending said drill bit in a wellbore on a drillstring and engaging and disintegrating a geologic formation with said drill bit, comprising: means for substantially continuously sensing at least one drillstring vibration characteristic with respect to time during selected drilling operations for a frequency range likely to encompass a frequency spectrum bit signal bandwidth for said drill bit; means for recording at least one signal representative of said at least one drillstring characteristic; means for determining spectral content of said at least one signal for said frequency spectrum bit signal bandwidth; ; means for monitoring at least one signal characteristic of said spectral content, and identifying bit whirl of said drill bit in said wellbore, as it occurs, from said at least one signal characteristic of said spectral content.

19. The method of drilling substantially as hereinbefore described with reference to the accompanying drawings.

20. Drill bit whirl detecting apparatus substantially as hereinbefore described with reference to the accompanying drawings.