CA2358777C - Method for determining formation slowness particularly adapted for measurement while drilling applications - Google Patents
Method for determining formation slowness particularly adapted for measurement while drilling applications Download PDFInfo
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- CA2358777C CA2358777C CA002358777A CA2358777A CA2358777C CA 2358777 C CA2358777 C CA 2358777C CA 002358777 A CA002358777 A CA 002358777A CA 2358777 A CA2358777 A CA 2358777A CA 2358777 C CA2358777 C CA 2358777C
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
- G01V1/44—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
- G01V1/48—Processing data
Abstract
A method is disclosed for calculating acoustic slowness of earth formation from signals measured at a plurality of receivers at axially spaced apart locations from a transmitter on a logging instrument. The method include calculating a multichannel coherence from the signals, and stacking the coherence from the signals detected from a plurality of actuations of the transmitter. The formation slowness is determined from the stacked coherence measure. In one embodiment, the coherence measure is slowness time coherence.
Description
i METHOD FOR DETERMINING FORMATION SLOWNESS PARTICULARLY
ADAPTED FOR MEASUREMENT WHILE DRILLING APPLICATIONS
1. BACKGROUND OF THE INVENTION
1.1 Field of the Invention The invention is related to sonic logging of earth formations penetrated by a wellbore.
More specifically, the invention is related to methods for processing sonic logging instrument signals to improve the quality of estimation of certain formation properties.
1.2 Description of Related Art Sonic logging of earth formations known in the art includes lowering a sonic logging instrument into a wellbore drilled through the formations. The instrument typically includes an acoustic transmitter and a plurality of receivers at spaced apart positions along the instrument from the transmitter. The transmitter is periodically actuated to emit pulses of acoustic energy into the wellbore, which travel through drilling fluid in the wellbore and along the wall of the wellbore. After travelling along the wellbore wall, some of the acoustic energy travels to the receivers, where it is detected. Various attributes of the detected acoustic energy are related to properties of interest of the formations through which the instrument passes, such as compressional velocity and shear velocity of the formation.
Processing known in the art for determining compressional and/or shear velocity includes correlation of the waveforms of the acoustic energy detected at each of the receivers. The correlation is performed using various values of slowness (inverse of velocity) until a degree of coherence between all the waveforms reaches a maximum. The value of slowness (or velocity) at which the degree of coherence is determined to be at a maximum is selected as the slowness or velocity for the formation interval in which the receivers are disposed at the time the transmitter is actuated.
The certainty and/or accuracy of the determination of velocity using the correlation technique can be improved by summing or "stacking" the waveforms from each receiver for a selected number of actuations of the transmitter as the instrument is moved along the wellbore.
This technique has proven very useful in cases where the logging instrument is lowered into the wellbore at the end of an electrical cable (known in the art as "wireline"
logging). This t technique, known in the art as calculating "slowness time coherence" (STC) is described, for example, in U. S. patent no. 4,594,691 issued to Kimball et al (assigned to the present assignee). Another velocity determination technique is described, for example, in U. S. patent no. 4,543,648 issued to Hsu (assigned to the present assignee).
It is known in the art to make measurements of formation acoustic properties while drilling the wellbore.
A sonic logging instrument useful for making while drilling measurements is described, for example, in U. S. patent no.
5,852,587 issued to Kostek et al (assigned to the present assignee). The technique for determining slowness by Stacking measurements from a plurality of receivers is generally applicable to be used with acoustic signals measured while drilling. However, the stacking techniques known in the art have proven less useful for measurements during the drilling of the wellbore (known as "logging-while-drilling"). The main reason for the stacking technique being less effective in logging-while-drilling applications is related to rotation and lateral movement of the instrument in the wellbore during drilling.
What is needed is a technique for improving the certainty and accuracy of velocity determination particularly suited for logging-while-drilling applications.
ADAPTED FOR MEASUREMENT WHILE DRILLING APPLICATIONS
1. BACKGROUND OF THE INVENTION
1.1 Field of the Invention The invention is related to sonic logging of earth formations penetrated by a wellbore.
More specifically, the invention is related to methods for processing sonic logging instrument signals to improve the quality of estimation of certain formation properties.
1.2 Description of Related Art Sonic logging of earth formations known in the art includes lowering a sonic logging instrument into a wellbore drilled through the formations. The instrument typically includes an acoustic transmitter and a plurality of receivers at spaced apart positions along the instrument from the transmitter. The transmitter is periodically actuated to emit pulses of acoustic energy into the wellbore, which travel through drilling fluid in the wellbore and along the wall of the wellbore. After travelling along the wellbore wall, some of the acoustic energy travels to the receivers, where it is detected. Various attributes of the detected acoustic energy are related to properties of interest of the formations through which the instrument passes, such as compressional velocity and shear velocity of the formation.
Processing known in the art for determining compressional and/or shear velocity includes correlation of the waveforms of the acoustic energy detected at each of the receivers. The correlation is performed using various values of slowness (inverse of velocity) until a degree of coherence between all the waveforms reaches a maximum. The value of slowness (or velocity) at which the degree of coherence is determined to be at a maximum is selected as the slowness or velocity for the formation interval in which the receivers are disposed at the time the transmitter is actuated.
The certainty and/or accuracy of the determination of velocity using the correlation technique can be improved by summing or "stacking" the waveforms from each receiver for a selected number of actuations of the transmitter as the instrument is moved along the wellbore.
This technique has proven very useful in cases where the logging instrument is lowered into the wellbore at the end of an electrical cable (known in the art as "wireline"
logging). This t technique, known in the art as calculating "slowness time coherence" (STC) is described, for example, in U. S. patent no. 4,594,691 issued to Kimball et al (assigned to the present assignee). Another velocity determination technique is described, for example, in U. S. patent no. 4,543,648 issued to Hsu (assigned to the present assignee).
It is known in the art to make measurements of formation acoustic properties while drilling the wellbore.
A sonic logging instrument useful for making while drilling measurements is described, for example, in U. S. patent no.
5,852,587 issued to Kostek et al (assigned to the present assignee). The technique for determining slowness by Stacking measurements from a plurality of receivers is generally applicable to be used with acoustic signals measured while drilling. However, the stacking techniques known in the art have proven less useful for measurements during the drilling of the wellbore (known as "logging-while-drilling"). The main reason for the stacking technique being less effective in logging-while-drilling applications is related to rotation and lateral movement of the instrument in the wellbore during drilling.
What is needed is a technique for improving the certainty and accuracy of velocity determination particularly suited for logging-while-drilling applications.
2. SUMMARY OF THE INVENTION
The invention provides a method for sonic logging of an earth formation. The method comprises repeatedly actuating an acoustic transmitter on a well logging instrument disposed in a wellbore traversing the formation) detecting acoustic signals with at least one receiver a disposed on the instrument; determining a coherence measure from the detected acoustic signals associated with the at least one transmitter actuations; and averaging the coherence measure for a plurality of the transmitter actuations to determine a property of the formation.
The invention also provides a method for sonic logging of an earth formation. The method comprises repeatedly actuating an acoustic transmitter on a well logging instrument disposed in a wellbore traversing the formation; detecting acoustic signals with at least one receiver disposed on the instrument; determining a coherence measure from the detected acoustic signals associated with the at least one transmitter actuations without stacking said signals; and averaging the coherence measure for a plurality of the transmitter actuations to determine the slowness of the formation.
The invention provides a method for sonic logging of an earth formation. The method comprises repeatedly actuating an acoustic transmitter on a well logging instrument disposed in a wellbore traversing the formation) detecting acoustic signals with at least one receiver a disposed on the instrument; determining a coherence measure from the detected acoustic signals associated with the at least one transmitter actuations; and averaging the coherence measure for a plurality of the transmitter actuations to determine a property of the formation.
The invention also provides a method for sonic logging of an earth formation. The method comprises repeatedly actuating an acoustic transmitter on a well logging instrument disposed in a wellbore traversing the formation; detecting acoustic signals with at least one receiver disposed on the instrument; determining a coherence measure from the detected acoustic signals associated with the at least one transmitter actuations without stacking said signals; and averaging the coherence measure for a plurality of the transmitter actuations to determine the slowness of the formation.
3. BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 shows a representative sonic logging-while-drilling instrument that can be used with the invention.
Figures 2A through 2D show synthesized receiver waveforms for a sonic logging instrument for four successive transmitter firings.
Figure 3A shows a flow chart of a prior art technique for determining formation slowness.
Figure 3B shows a flow chart of an embodiment of the method of the invention.
Figure 4 shows an example of a "synthesized transmitter array" technique for acquiring and processing sonic signals according to one embodiment of the invention.
Figures 5A and 5B show a comparison of results obtained using prior art slowness time coherence ("STC") processing and STC processing according to the invention, using as signals the waveforms shown in Figures 2A through 2D.
Figure 6 shows an example of results obtained using one embodiment of the invention compared with results obtained using prior art methods.
Figure 1 shows a representative sonic logging-while-drilling instrument that can be used with the invention.
Figures 2A through 2D show synthesized receiver waveforms for a sonic logging instrument for four successive transmitter firings.
Figure 3A shows a flow chart of a prior art technique for determining formation slowness.
Figure 3B shows a flow chart of an embodiment of the method of the invention.
Figure 4 shows an example of a "synthesized transmitter array" technique for acquiring and processing sonic signals according to one embodiment of the invention.
Figures 5A and 5B show a comparison of results obtained using prior art slowness time coherence ("STC") processing and STC processing according to the invention, using as signals the waveforms shown in Figures 2A through 2D.
Figure 6 shows an example of results obtained using one embodiment of the invention compared with results obtained using prior art methods.
4. DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS
A representative sonic logging-while-drilling ("LWD") instrument that can be used with a method according to the invention is shown in Figure 1. The instrument 10 is shown disposed in a wellbore 12 drilled through earth formations 20. The wellbore 12 is typically filled with a liquid drilling fluid 14 called "drilling mud" when drilling operations are in progress. The instrument 10 is generally mounted in a heavy weight drill collar 13, which includes a passage 13A through its center for pumping the drilling fluid 14 to a mud motor (not shown) and/or a drill bit (not shown) at the bottom of a drill string (not shown). The logging instrument 10 includes one or more acoustic transmitters 16 positioned in the wall of the collar 13, and a plurality of spaced apart acoustic receivers 18 also disposed in the wall of the collar 13. The receivers 18 are shown spaced apart from each other, along the longitudinal axis of the instrument 10, at a selected distance h. The one of the receivers 18 closest to the transmitter 16 is 3a CA 02358777,2004-03-16 p 79350-15 axially spaced therefrom by a selected distance a. It is to be understood that the distances a and h should be known in order to process signals according to the method of the invention, but 3b the actual distances used for any particular sonic logging instrument are not a limitation on the invention. It should also be understood that even though the instrument shown in Figure 1 has the same distance h between each of the receivers, it is not necessary for purposes of the invention that the distance between each of the receivers on the instrument be the same. The instrument shown in Figure 1 can be similar to one described in U. S. patent no. 5,852,587 issued to Kostek et al, but it should be clearly understood that the actual configuration of the instrument used with the method of the invention is not a limitation on the invention. It is preferred that the instrument include at least one transmitter and a plurality of axially spaced apart receivers.
It should also be clearly understood that by the principle of reciprocity, a different configuration of sonic logging instrument, wherein the receivers ( 18 as shown in Figure 1 ) are substituted by transmitters, and the transmitter (16 in Figure 1) is substituted by receivers will also work with the method of this invention. When using an instrument having a plurality of transmitters, signals are detected at the receiver for a firing of each of the transmitters. The signals can be processed according to any known method for determining coherence, as will be further explained, and, as will also be further explained, the measures of coherence can then be stacked to determine velocity For the instrument shown in Figure 1, periodically the transmitter 16 is actuated or "fired", sending pulses of acoustic energy, shown generally at 22, into the drilling fluid 14 where they travel along the wall of the wellbore 12, and are eventually detected by each of the receivers 18. As is well known in the art, LWD instruments are typically rotated during drilling operations in order to turn the drill bit (not shown). The manner of operating the instrument 10 while drilling is under way, and the equipment associated with drilling the wellbore are known in the art, and are described, for example, in the Kostek et al'S87 patent referred to previously. It is not required to rotate the instrument during sonic logging operations according to this invention, however.
Depending on the axial spacings a and h, on the types of transmitter and receivers used, and on the acoustic characteristics of the particular earth formations penetrated by the wellbore adjacent the instrument 10, the receivers 18 will generate electrical signals in response to the acoustic energy which have particular waveforms. Examples of such waveforms are shown for the receivers 18 on the instrument 10 in Figure 2A at 30, 32, 34, and 36.
Typically each waveform 30, 32, 34, and 36 will include a relatively high amplitude event 30A, 32A, 34A, 36A, respectively, which corresponds to the arrival from the earth formation of the energy which was emitted from the transmitter (16 in Figure 1) and has passed along the wellbore wall. The time at which each high amplitude event 30A, 32A, 34A, 36A actually occurs in each waveform depends on the axial spacing of the particular receiver and on the acoustic properties (particularly acoustic velocity) of the particular earth formations between the transmitter and receivers. Similarly, examples of waveforms made by successive firings of the transmitter (16 in Figure 10) are shown in Figure 2B at 38, 40, 42 and 44; in Figure 2C at 46, 48, 50 and 52; and in Figure 2D at 54, 56, 58 and 6D. Prior art methods for determining velocity included calculating a "slowness time coherence" between the signals detected by the receivers. To improve signal to noise ratio, the coherence techniques of the prior art included summing or "stacking" the waveforms from the same receiver from multiple transmitter firings, such as shown in Figures 2A
through 2D, and determining the slowness time coherence from the stacked waveforms. It should be noted that the example waveforms of Figures 2A through 2D are simulated compressional waveforms for an earth formation having a compressional interval velocity of 100 microseconds per foot (328 microseconds/meter). Random noise has been added to each simulated waveform. The actual waveforms of the detected acoustic energy, the arrival times and the noise type will of course depend on the various factors explained above. The principle of the invention is well illustrated by the simulated waveforms, however.
Particularly in LWD applications, the prior art method for calculating slowness, wherein waveforms from successive transmitter firings are stacked, has been less than satisfactory because waveforms from successive transmitter firings at the same receiver have been known to vary so much in character that stacking may result in near total loss of the signal. As previously explained, a substantial cause of the waveform variation is believed to be rotation and lateral motion of the logging instrument during drilling.
Figure 3A shows a flow chart of a conventional technique for calculating slowness, wherein the transmitter is repeatedly fired at 62, 66, 70 and the measured signal waveforms are stacked together at 71 by combining samples taken from the different transmitter actuations. A
coherence measurement is then performed on the stacked waveforms, at 76. A coherence plot 77 (See Figure 5A) is then obtained from the coherence measurement and the formation slowness is derived from the coherence measurement.
In one embodiment of the invention, waveforms from each transmitter firing are used to determine a slowness time coherence. The slowness time coherence from a plurality of transmitter firings are then stacked to determine a stacked coherence. The stacked slowness time coherence is used to determine the formation slowness in any manner known in the art. See for example, the previously referred to Kimball et al '691 patent. This embodiment is shown in flow chart form in Figure 3B. Transmitter firing number 1, at 62, generates waveforms such as 30-36 in Figure 2A. These waveforms are used to calculate a coherence measure at 64 and to generate a slowness time coherence plot at 65. Similarly, for transmitter firing number 2, at 66, the resulting receiver waveforms are used CA 02358777'2004-03-16 to calculate a coherence measure at 68 and to generate a slowness time coherence plot, at 69. This continues for a selected number of transmitter firings, N, at 70 to calculate the N-th coherence measure at 72 and to generate the N-th slowness time coherence plot at 73. The N slowness time coherence plots are stacked at 74 to generate a stacked or averaged slowness time coherence plot. The stacked or averaged slowness time coherence ("STC") is used to determine the formation slowness using any manner known in the art. One such method is described, for example, in U.
S. patent no. 4,543,648 issued to Hsu.
Slowness time coherence is a preferred form of calculating a multichannel coherence measure of the detected acoustic energy. The invention contemplates within its scope other methods for calculating multichannel coherence of the detected acoustic energy. Other multichannel coherence measures are described, for example, in, N. S. Neidell et al, Semblance and Other Coherency Measures for Mult.ichannel Data, Geophysics, vol. 36, no. 3, pp. 482-497, Society of Exploration Geophysicists (1971). Other embodiments of the invention may use types of coherence calculation other than semblance to determine velocity.
The example shown in Figure 1 contemplates determining velocity as described herein for an interval of earth formation corresponding to the axial position of the receivers (18 in Figure 1). In the example of Figure 1, the instrument 10, in practical terms, does not move as the acoustic energy from a transmitter firing is detected at the receivers. The coherence calculated from each such firing, as previously explained, can be stacked with the coherence measure obtained from other firings of the transmitter.
A representative sonic logging-while-drilling ("LWD") instrument that can be used with a method according to the invention is shown in Figure 1. The instrument 10 is shown disposed in a wellbore 12 drilled through earth formations 20. The wellbore 12 is typically filled with a liquid drilling fluid 14 called "drilling mud" when drilling operations are in progress. The instrument 10 is generally mounted in a heavy weight drill collar 13, which includes a passage 13A through its center for pumping the drilling fluid 14 to a mud motor (not shown) and/or a drill bit (not shown) at the bottom of a drill string (not shown). The logging instrument 10 includes one or more acoustic transmitters 16 positioned in the wall of the collar 13, and a plurality of spaced apart acoustic receivers 18 also disposed in the wall of the collar 13. The receivers 18 are shown spaced apart from each other, along the longitudinal axis of the instrument 10, at a selected distance h. The one of the receivers 18 closest to the transmitter 16 is 3a CA 02358777,2004-03-16 p 79350-15 axially spaced therefrom by a selected distance a. It is to be understood that the distances a and h should be known in order to process signals according to the method of the invention, but 3b the actual distances used for any particular sonic logging instrument are not a limitation on the invention. It should also be understood that even though the instrument shown in Figure 1 has the same distance h between each of the receivers, it is not necessary for purposes of the invention that the distance between each of the receivers on the instrument be the same. The instrument shown in Figure 1 can be similar to one described in U. S. patent no. 5,852,587 issued to Kostek et al, but it should be clearly understood that the actual configuration of the instrument used with the method of the invention is not a limitation on the invention. It is preferred that the instrument include at least one transmitter and a plurality of axially spaced apart receivers.
It should also be clearly understood that by the principle of reciprocity, a different configuration of sonic logging instrument, wherein the receivers ( 18 as shown in Figure 1 ) are substituted by transmitters, and the transmitter (16 in Figure 1) is substituted by receivers will also work with the method of this invention. When using an instrument having a plurality of transmitters, signals are detected at the receiver for a firing of each of the transmitters. The signals can be processed according to any known method for determining coherence, as will be further explained, and, as will also be further explained, the measures of coherence can then be stacked to determine velocity For the instrument shown in Figure 1, periodically the transmitter 16 is actuated or "fired", sending pulses of acoustic energy, shown generally at 22, into the drilling fluid 14 where they travel along the wall of the wellbore 12, and are eventually detected by each of the receivers 18. As is well known in the art, LWD instruments are typically rotated during drilling operations in order to turn the drill bit (not shown). The manner of operating the instrument 10 while drilling is under way, and the equipment associated with drilling the wellbore are known in the art, and are described, for example, in the Kostek et al'S87 patent referred to previously. It is not required to rotate the instrument during sonic logging operations according to this invention, however.
Depending on the axial spacings a and h, on the types of transmitter and receivers used, and on the acoustic characteristics of the particular earth formations penetrated by the wellbore adjacent the instrument 10, the receivers 18 will generate electrical signals in response to the acoustic energy which have particular waveforms. Examples of such waveforms are shown for the receivers 18 on the instrument 10 in Figure 2A at 30, 32, 34, and 36.
Typically each waveform 30, 32, 34, and 36 will include a relatively high amplitude event 30A, 32A, 34A, 36A, respectively, which corresponds to the arrival from the earth formation of the energy which was emitted from the transmitter (16 in Figure 1) and has passed along the wellbore wall. The time at which each high amplitude event 30A, 32A, 34A, 36A actually occurs in each waveform depends on the axial spacing of the particular receiver and on the acoustic properties (particularly acoustic velocity) of the particular earth formations between the transmitter and receivers. Similarly, examples of waveforms made by successive firings of the transmitter (16 in Figure 10) are shown in Figure 2B at 38, 40, 42 and 44; in Figure 2C at 46, 48, 50 and 52; and in Figure 2D at 54, 56, 58 and 6D. Prior art methods for determining velocity included calculating a "slowness time coherence" between the signals detected by the receivers. To improve signal to noise ratio, the coherence techniques of the prior art included summing or "stacking" the waveforms from the same receiver from multiple transmitter firings, such as shown in Figures 2A
through 2D, and determining the slowness time coherence from the stacked waveforms. It should be noted that the example waveforms of Figures 2A through 2D are simulated compressional waveforms for an earth formation having a compressional interval velocity of 100 microseconds per foot (328 microseconds/meter). Random noise has been added to each simulated waveform. The actual waveforms of the detected acoustic energy, the arrival times and the noise type will of course depend on the various factors explained above. The principle of the invention is well illustrated by the simulated waveforms, however.
Particularly in LWD applications, the prior art method for calculating slowness, wherein waveforms from successive transmitter firings are stacked, has been less than satisfactory because waveforms from successive transmitter firings at the same receiver have been known to vary so much in character that stacking may result in near total loss of the signal. As previously explained, a substantial cause of the waveform variation is believed to be rotation and lateral motion of the logging instrument during drilling.
Figure 3A shows a flow chart of a conventional technique for calculating slowness, wherein the transmitter is repeatedly fired at 62, 66, 70 and the measured signal waveforms are stacked together at 71 by combining samples taken from the different transmitter actuations. A
coherence measurement is then performed on the stacked waveforms, at 76. A coherence plot 77 (See Figure 5A) is then obtained from the coherence measurement and the formation slowness is derived from the coherence measurement.
In one embodiment of the invention, waveforms from each transmitter firing are used to determine a slowness time coherence. The slowness time coherence from a plurality of transmitter firings are then stacked to determine a stacked coherence. The stacked slowness time coherence is used to determine the formation slowness in any manner known in the art. See for example, the previously referred to Kimball et al '691 patent. This embodiment is shown in flow chart form in Figure 3B. Transmitter firing number 1, at 62, generates waveforms such as 30-36 in Figure 2A. These waveforms are used to calculate a coherence measure at 64 and to generate a slowness time coherence plot at 65. Similarly, for transmitter firing number 2, at 66, the resulting receiver waveforms are used CA 02358777'2004-03-16 to calculate a coherence measure at 68 and to generate a slowness time coherence plot, at 69. This continues for a selected number of transmitter firings, N, at 70 to calculate the N-th coherence measure at 72 and to generate the N-th slowness time coherence plot at 73. The N slowness time coherence plots are stacked at 74 to generate a stacked or averaged slowness time coherence plot. The stacked or averaged slowness time coherence ("STC") is used to determine the formation slowness using any manner known in the art. One such method is described, for example, in U.
S. patent no. 4,543,648 issued to Hsu.
Slowness time coherence is a preferred form of calculating a multichannel coherence measure of the detected acoustic energy. The invention contemplates within its scope other methods for calculating multichannel coherence of the detected acoustic energy. Other multichannel coherence measures are described, for example, in, N. S. Neidell et al, Semblance and Other Coherency Measures for Mult.ichannel Data, Geophysics, vol. 36, no. 3, pp. 482-497, Society of Exploration Geophysicists (1971). Other embodiments of the invention may use types of coherence calculation other than semblance to determine velocity.
The example shown in Figure 1 contemplates determining velocity as described herein for an interval of earth formation corresponding to the axial position of the receivers (18 in Figure 1). In the example of Figure 1, the instrument 10, in practical terms, does not move as the acoustic energy from a transmitter firing is detected at the receivers. The coherence calculated from each such firing, as previously explained, can be stacked with the coherence measure obtained from other firings of the transmitter.
a m Figure 4 shows an alternative method for determining formation velocity according to the method of the invention, wherein the instrument 10 is moved axially along the wellbore between successive firings of the transmitter so that the velocity can be determined in an interval corresponding to the movement of the instrument. In Figure 4, the instrument 10 is shown at successive axial positions P1 through P20 along the wellbore. Ones of the receivers 18 spanning a common selected interval, shown at 100, can have their signals used to generate a coherence measure. As the instrument 10 moves along the wellbore, such as from P1 to P9, for example, the coherence measure from each set of receiver signals corresponding to the common interval 100 can be stacked to determine velocity in the axial interval spanned by the transmitter 16 as the instrument moves from P1 to P9. This method is well explained in U. S. patent no. 4,543,648 issued to Hsu as applied to prior art coherence calculation techniques. It has been determined that this method is equally applicable to the stacked coherence technique of this invention.
A comparison of the results of processing according to prior art methods with those obtained using the method of the invention can be observed in Figures 5A and 5B. Figure 5A shows a plot of STC obtained using the waveforms shown in Figures 2A through 2D, wherein the waveforms from each of the receivers is stacked over multiple actuations of the transmitter. As can be observed at 78 in Figure 5A, the coherence of the stacked waveforms is relatively low, and the calculated slowness is not correct. Figure 5B shows a plot of semblance correlation calculated using the method of the invention and the 7a CA 02358777'2004-03-16 P
waveforms shown in Figures 2A through 2D. As can be observed at 80, the semblance shows a much higher coherence value and the calculated slowness is substantially correct.
It should be noted also that while the invention is particularly suited to LWD applications, in theory there is no reason that the method of the invention could also be applied to wireline-conveyed sonic logging instruments, coiled tubing conveyed logging measurements, or logging measurements made by any other conveyance mechanism known in the art.
In LWD applications, different methods for communicating calculated slowness from the instrument (10 in Figure 1) to the earth s surface can be used. First, the slowness can be periodically calculated according to the process previously described herein in a processor (not shown in the Figures) disposed in the instrument. Such processors and methods for programming such processors to calculate slowness are known in the art. See for example, U. S. patents nos. 5,594,706 issued to Shenoy et al, and 5,582,587 issued to Kostek et al (both assigned to the present assignee). After the slowness is calculated, the value thereof can be applied to a telemetry system which modulates the pressure of the drilling mud (14 in Figure 1) according to a predetermined pattern. This type of telemetry is also known in the art, and an example of its use in sonic LWD is described in the Kostel et al. '587 patent referred to earlier.
Alternatively, or in conjunction with transmitting values of slowness in mud pressure modulation telemetry, the values of slowness, the slowness time coherence plots, and 7b a 79350-15 even the receiver signals can be stored in a memory (not shown in the Figures) associated with the processor. The contents of the memory (not shown) can be downloaded to a surface recording and interpretation system (not shown in the Figures) when the instrument is withdrawn from the wellbore to the earth's surface. LWD instrument memory interrogation techniques are known in the art. See for example, U. S. patent no. 4,216,536 issued to More. The data stored in the 7c memory can be used to determine slowness, either directly if slowness values are stored in the memory, or by processing stored waveforms and/or slowness time coherence data according to the embodiment of the invention described previously herein.
An example of results obtained using the method described herein to determine velocity as compared with a prior art method is shown in Figure 6. Velocity (slowness) calculation using the prior art method on data acquired using an LWD instrument is shown at curve 106. Velocity measurement using a wireline-conveyed instrument, using techniques known in the art for calculating slowness, is shown at curve 102. LWD data processed according to the method of the invention is shown at curve 104. As can be observed in Figure 6, the method of the invention can produce results comparable to wireline-acquired data from LWD acquired data, where prior art methods may provide noisy and/or erratic results from such data.
The method of the invention provides a technique for calculating velocity from sonic signals acquired during drilling of a wellbore which can have improved signal to noise, accuracy and certainty of result than prior art method.
s
A comparison of the results of processing according to prior art methods with those obtained using the method of the invention can be observed in Figures 5A and 5B. Figure 5A shows a plot of STC obtained using the waveforms shown in Figures 2A through 2D, wherein the waveforms from each of the receivers is stacked over multiple actuations of the transmitter. As can be observed at 78 in Figure 5A, the coherence of the stacked waveforms is relatively low, and the calculated slowness is not correct. Figure 5B shows a plot of semblance correlation calculated using the method of the invention and the 7a CA 02358777'2004-03-16 P
waveforms shown in Figures 2A through 2D. As can be observed at 80, the semblance shows a much higher coherence value and the calculated slowness is substantially correct.
It should be noted also that while the invention is particularly suited to LWD applications, in theory there is no reason that the method of the invention could also be applied to wireline-conveyed sonic logging instruments, coiled tubing conveyed logging measurements, or logging measurements made by any other conveyance mechanism known in the art.
In LWD applications, different methods for communicating calculated slowness from the instrument (10 in Figure 1) to the earth s surface can be used. First, the slowness can be periodically calculated according to the process previously described herein in a processor (not shown in the Figures) disposed in the instrument. Such processors and methods for programming such processors to calculate slowness are known in the art. See for example, U. S. patents nos. 5,594,706 issued to Shenoy et al, and 5,582,587 issued to Kostek et al (both assigned to the present assignee). After the slowness is calculated, the value thereof can be applied to a telemetry system which modulates the pressure of the drilling mud (14 in Figure 1) according to a predetermined pattern. This type of telemetry is also known in the art, and an example of its use in sonic LWD is described in the Kostel et al. '587 patent referred to earlier.
Alternatively, or in conjunction with transmitting values of slowness in mud pressure modulation telemetry, the values of slowness, the slowness time coherence plots, and 7b a 79350-15 even the receiver signals can be stored in a memory (not shown in the Figures) associated with the processor. The contents of the memory (not shown) can be downloaded to a surface recording and interpretation system (not shown in the Figures) when the instrument is withdrawn from the wellbore to the earth's surface. LWD instrument memory interrogation techniques are known in the art. See for example, U. S. patent no. 4,216,536 issued to More. The data stored in the 7c memory can be used to determine slowness, either directly if slowness values are stored in the memory, or by processing stored waveforms and/or slowness time coherence data according to the embodiment of the invention described previously herein.
An example of results obtained using the method described herein to determine velocity as compared with a prior art method is shown in Figure 6. Velocity (slowness) calculation using the prior art method on data acquired using an LWD instrument is shown at curve 106. Velocity measurement using a wireline-conveyed instrument, using techniques known in the art for calculating slowness, is shown at curve 102. LWD data processed according to the method of the invention is shown at curve 104. As can be observed in Figure 6, the method of the invention can produce results comparable to wireline-acquired data from LWD acquired data, where prior art methods may provide noisy and/or erratic results from such data.
The method of the invention provides a technique for calculating velocity from sonic signals acquired during drilling of a wellbore which can have improved signal to noise, accuracy and certainty of result than prior art method.
s
Claims (7)
1. A method for sonic logging of an earth formation, comprising:
(a) repeatedly actuating an acoustic transmitter on a well logging instrument disposed in a wellbore traversing the formation;
(b) detecting acoustic signals with at least one receiver disposed on the instrument;
(c) determining a coherence measure from the detected acoustic signals associated with the at least one transmitter actuations; and (d) averaging the coherence measure for a plurality of the transmitter actuations to determine a property of the formation.
(a) repeatedly actuating an acoustic transmitter on a well logging instrument disposed in a wellbore traversing the formation;
(b) detecting acoustic signals with at least one receiver disposed on the instrument;
(c) determining a coherence measure from the detected acoustic signals associated with the at least one transmitter actuations; and (d) averaging the coherence measure for a plurality of the transmitter actuations to determine a property of the formation.
2. The method of claim 1 wherein the determined property is the slowness of the formation.
3. The method of claim 1 wherein step (c) includes calculating a slowness time coherence.
4. The method of claim 1 wherein step (c) includes producing a coherence plot from the detected acoustic signals.
5. The method of claim 1 wherein step (d) includes producing an average coherence plot from the averaged coherence measure.
6. The method of claim 1 wherein the logging instrument is adapted for disposal within the wellbore during the drilling of said wellbore.
7. A method for sonic logging of an earth formation, comprising:
(a) repeatedly actuating an acoustic transmitter on a well logging instrument disposed in a wellbore traversing the formation;
(b) detecting acoustic signals with at least one receiver disposed on the instrument;
(c) determining a coherence measure from the detected acoustic signals associated with the at least one transmitter actuations without stacking said signals; and (d) averaging the coherence measure for a plurality of the transmitter actuations to determine the slowness of the formation.
(a) repeatedly actuating an acoustic transmitter on a well logging instrument disposed in a wellbore traversing the formation;
(b) detecting acoustic signals with at least one receiver disposed on the instrument;
(c) determining a coherence measure from the detected acoustic signals associated with the at least one transmitter actuations without stacking said signals; and (d) averaging the coherence measure for a plurality of the transmitter actuations to determine the slowness of the formation.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US68843700A | 2000-10-16 | 2000-10-16 | |
| US09/688,437 | 2000-10-16 |
Publications (2)
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| CA2358777A1 CA2358777A1 (en) | 2002-04-16 |
| CA2358777C true CA2358777C (en) | 2005-01-25 |
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|---|---|---|---|
| CA002358777A Expired - Fee Related CA2358777C (en) | 2000-10-16 | 2001-10-15 | Method for determining formation slowness particularly adapted for measurement while drilling applications |
Country Status (4)
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|---|---|
| US (1) | US7013217B2 (en) |
| CA (1) | CA2358777C (en) |
| GB (1) | GB2372322B (en) |
| NO (1) | NO20015006L (en) |
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| Publication number | Priority date | Publication date | Assignee | Title |
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| US6957572B1 (en) | 2004-06-21 | 2005-10-25 | Schlumberger Technology Corporation | Apparatus and methods for measuring mud slowness in a borehole |
| US7334651B2 (en) * | 2004-07-21 | 2008-02-26 | Schlumberger Technology Corporation | Kick warning system using high frequency fluid mode in a borehole |
| US7764572B2 (en) * | 2004-12-08 | 2010-07-27 | Schlumberger Technology Corporation | Methods and systems for acoustic waveform processing |
| US7516015B2 (en) * | 2005-03-31 | 2009-04-07 | Schlumberger Technology Corporation | System and method for detection of near-wellbore alteration using acoustic data |
| US7251566B2 (en) * | 2005-03-31 | 2007-07-31 | Schlumberger Technology Corporation | Pump off measurements for quality control and wellbore stability prediction |
| US8009509B2 (en) * | 2008-04-09 | 2011-08-30 | Schlumberger Technology Corporation | Automated mud slowness estimation |
| US10317545B2 (en) * | 2012-03-12 | 2019-06-11 | Schlumberger Technology Corporation | Methods and apparatus for waveform processing |
| CN103388473B (en) * | 2012-05-10 | 2016-04-13 | 中国石油集团长城钻探工程有限公司 | The method of direct-wave jamming, system and acoustic logging instrument is eliminated in acoustic logging |
| WO2016123432A1 (en) * | 2015-01-30 | 2016-08-04 | Halliburton Energy Services, Inc. | Peak tracking and rejection in acoustic logs |
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| US3597727A (en) * | 1968-12-30 | 1971-08-03 | Chevron Res | Method of attenuating multiple seismic signals in the determination of inline and cross dips employing cross-steered seismic data |
| US4594691A (en) * | 1981-12-30 | 1986-06-10 | Schlumberger Technology Corporation | Sonic well logging |
| US4543648A (en) * | 1983-12-29 | 1985-09-24 | Schlumberger Technology Corporation | Shot to shot processing for measuring a characteristic of earth formations from inside a borehole |
| US4698793A (en) * | 1984-05-23 | 1987-10-06 | Schlumberger Technology Corporation | Methods for processing sonic data |
| US4819214A (en) * | 1987-10-29 | 1989-04-04 | Amoco Corporation | Sonic logging system |
| US5852587A (en) * | 1988-12-22 | 1998-12-22 | Schlumberger Technology Corporation | Method of and apparatus for sonic logging while drilling a borehole traversing an earth formation |
| US5392213A (en) * | 1992-10-23 | 1995-02-21 | Exxon Production Research Company | Filter for removal of coherent noise from seismic data |
| US5594706A (en) * | 1993-12-20 | 1997-01-14 | Schlumberger Technology Corporation | Downhole processing of sonic waveform information |
| US5510582A (en) * | 1995-03-06 | 1996-04-23 | Halliburton Company | Acoustic attenuator, well logging apparatus and method of well logging |
| GB2309082B (en) * | 1996-01-09 | 1999-12-01 | Geco As | Noise filtering method |
| WO1998048508A2 (en) | 1997-04-18 | 1998-10-29 | University Of Utah Research Foundation | Method and apparatus for multichannel active noise and vibration control |
| US6026913A (en) * | 1997-09-30 | 2000-02-22 | Halliburton Energy Services, Inc. | Acoustic method of connecting boreholes for multi-lateral completion |
| US6082484A (en) * | 1998-12-01 | 2000-07-04 | Baker Hughes Incorporated | Acoustic body wave dampener |
| GB9907620D0 (en) * | 1999-04-01 | 1999-05-26 | Schlumberger Ltd | Processing sonic waveform measurements |
| GB2357841B (en) * | 1999-10-06 | 2001-12-12 | Schlumberger Ltd | Processing sonic waveform measurements from array borehole logging tools |
| US6477112B1 (en) * | 2000-06-20 | 2002-11-05 | Baker Hughes Incorporated | Method for enhancing resolution of earth formation elastic-wave velocities by isolating a wave event and matching it for all receiver combinations on an acoustic-array logging tool |
| US6748329B2 (en) * | 2000-12-08 | 2004-06-08 | Halliburton Energy Services, Inc. | Acoustic signal processing method using array coherency |
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- 2001-10-09 GB GB0124179A patent/GB2372322B/en not_active Expired - Lifetime
- 2001-10-15 NO NO20015006A patent/NO20015006L/en not_active Application Discontinuation
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| GB2372322A (en) | 2002-08-21 |
| NO20015006L (en) | 2002-04-17 |
| US20040006428A1 (en) | 2004-01-08 |
| GB2372322B (en) | 2003-04-16 |
| CA2358777A1 (en) | 2002-04-16 |
| US7013217B2 (en) | 2006-03-14 |
| GB0124179D0 (en) | 2001-11-28 |
| NO20015006D0 (en) | 2001-10-15 |
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