JPH0434706B2 - - Google Patents

Description

DETAILED DESCRIPTION OF THE INVENTION The present invention relates to cement bond logging, and more particularly to a method and apparatus for measuring the rate of attenuation of acoustic energy across a casing cemented within a borehole.

To complete a well, a series of casings or pipes are set within the borehole and cement is placed within the annular gap between the casing and the borehole, primarily to separate the oil and gas producing formations from each other and from the water content. inject. Clearly, if this cementation fails to separate one zone from another, pressurized fluid from one zone will enter and contaminate another adjacent production zone. In particular, water intrusion can cause undesirable water cutting in the production zone.
There is a risk of making the well uneconomical.

Obtaining a correct depiction of the conditions behind the casing is problematic because of the difficulty in propagating signals through the casing walls. Various previous proposals have been made to determine the separation effect (i.e., blocking or sealing properties) of cement behind the casing, but the effective presence of cement in the annular gap between the casing and the formation has been There has never been a complete success in determining an unambiguous decision. Furthermore, it has not been possible to reliably measure the quality of the cement bond between the casing and the cement.

Although the mere presence or absence of cement within the annular gap between the casing and the formation is valuable information, it does not completely describe the condition of the cement. Even though cement is present within the annular gap, channels or insufficient seals allow fluid communication between adjacent formations.

The use of the term "bond" in connection with the relationship between cement and casing or formation is somewhat ambiguous. This is because it is not necessary to bond along the entire boundary between the casing and the cement or between the cement and the formation to prevent fluid communication between adjacent porous zones. All that is required of the bond is a relationship that prevents fluid ingress. In the following description, bond should be taken to mean that the separation of zones by cement is sufficient to prevent fluid ingress between these zones.

Examples of prior art developed to measure the quality of cement bonds to casings include, for example, U.S. Pat.
There is number 3292246. These systems generally use acoustic principles, where an acoustic signal is transmitted between a transmitter and a receiver. Signals that arrive early at the receiver (this early arriving signal is usually a casing signal, since under average conditions acoustic energy generally travels faster through the casing than through the surrounding cement or formations) The amplitude of is measured as determining the quality of the bond of the cement to the casing. If the bond is good, the casing signal is expected to be attenuated as energy dissipates from the casing into the cement and surrounding formations. On the other hand, if the bond is absent or weak, the casing signal will be relatively less attenuated.

A more sophisticated technique for determining the quality of cement in the annular gap between the casing and the formation is disclosed in J.D. Synot, US Pat. This technique records the amplitude of the echoed early (casing) signal and then integrates the total energy of a selected late portion of the acoustic signal to obtain a second measure of cement bond quality. Display. Even when a weak casing signal is not available, this additional step of observing the total energy obtained by integrating the slow part of the signal allows the detection within the casing, annular gap, and formation system. The presence of cement can be confirmed. F.
Details of related methods are disclosed in US Pat.

Although the methods and apparatus described above provide extremely useful information, it is desirable to more precisely determine the quality of cement bonds. It is known that the energy content of the acoustic logging signal reaching the receiver depends on factors other than the quality of the cement bond to the casing, ie the integrity of the cement column (sometimes referred to as cement quality). It was found that the following factors have a considerable effect on the arriving signal. receiver sensitivity, formation hardness, acoustic logging tool eccentricity, hot environment and temperature variations within the wellbore, casing type, and borehole and casing diameters and their shapes or geometries.

It is therefore clear that a method and apparatus for determining the quality of cement bonds in cased boreholes that reduced the deleterious effects of the above factors would be highly desirable.

A general object of the present invention is to provide an improved method and apparatus for cement bond logging of cased boreholes.

The method of the present invention achieves this and other objects by: two longitudinally spaced acoustic transmitters, and a measurable signal-to-noise ratio and prior to the arrival of the formation signal. The casing is spaced longitudinally between the acoustic transmitters with a transmitter-receiver spacing such that the signal reaches and allows an eccentricity equal to 7.62 mm (0.3 inches). placing a tool in the well having two acoustic receivers; repeatedly energizing the acoustic transmitter to provide acoustic energy into a casing surrounding the well tool; from the first transmitter through the casing to the receiver; detecting by a receiver acoustic energy arriving through the casing from said second transmitter subsequent to activation of said first transmitter; measure the peak amplitude of the selected portion of the acoustic casing signal detected by each receiver at a time; determine the ratio of the peak amplitudes with energization of the first transmitter; Determine the ratio of the peak amplitudes with transmitter energization; combine these ratios to generate a function representing the attenuation of acoustic energy traveling through the casing; and as a function of tool position within the borehole. The steps of recording attenuation provide a measure of the quality of the cement bond to the casing within the borehole.

Also, an apparatus according to the invention for obtaining a measure of the quality of a cement bond for a casing in a borehole includes: two longitudinally spaced acoustic transmitters, and approximately 2.4 feet and 103.63 cm from each transmitter, respectively. A well tool having at least two acoustic receivers spaced longitudinally between the acoustic transmitters at a spacing of 3.4 feet (cm); the acoustic transmitters are repeatedly energized to means for supplying acoustic energy within a surrounding casing; said receiver detecting energy reaching the receiver from a first transmitter through the casing; and transmitting a second transmission following activation of the first transmitter. the apparatus is also adapted to detect energy arriving from the receiver through the casing; the apparatus further includes means for measuring the peak amplitude of a selected portion of the acoustic casing signal detected at each receiver;
Means for determining the ratio of the peak amplitudes upon activation of the second transmitter; Means for determining the ratio of the peak amplitudes upon activation of the second transmitter; Combining these ratios and driving the transmitter through the casing. and means for recording the rate of attenuation as a function of tool position within the borehole.

In another aspect, an apparatus for determining the quality of a cement bond in a cased, cemented borehole that traverses a high-velocity formation includes: at least one transmitter that transmits acoustic energy from the borehole into the casing and surrounding formation; ;From this transmitter
Spaced at a distance of no more than 30.48 cm (1 foot),
at least one receiver for receiving and generating an electrical signal representative of the refracted portion of the transmitted energy; means for generating a signal representative of the peak amplitude of the first half cycle of the received energy; and a function of depth. The apparatus is equipped with means for recording this peak amplitude.

In yet another aspect, a logging tool used to determine cement bond quality in a cased cemented diagonal borehole; houses a plurality of transducers including an acoustic transmitter and an acoustic receiver. a rigid lower portion; a rigid upper portion containing the electronics cartridge; a centering device coupled to the lower portion at intervals to maintain the lower portion centered in the cased borehole; a lower portion; and means for mechanically decoupling the lower portion from the upper portion so that the weight of the lower portion is solely that supported by the centering device in the diagonal borehole.

The novel features of the invention are pointed out with particularity in the claims. The operation of the present invention as well as other objects and advantages will be more fully understood from the following description taken in conjunction with the accompanying drawings.

A logging system for carrying out the invention shown in FIG. 1 includes an elongated logging tool 10;
The tool 10 is provided with a centering device 11 for keeping the tool in the borehole 12 as effectively as possible. Borehole 12 is shown filled with fluid 13. Tool 10 is Tool 10
It is suspended in the wellbore by a cable 15 extending from the top end to the ground surface. The cable, typically a monocable 15, is wound onto the winch. Although the winch is not shown, its operation moves the tool 10 into the wellbore 12, as is well known in the art.
It is intended to be raised and lowered within the building. The display of the depth of the tool 10 suspended in the borehole 12 is as follows:
Means for measuring the length of cable 15 (not shown)
It can be obtained by This information is utilized to derive one of the functions in a typical well log.

The tool 10 itself is divided into several sections. The lower section between the centerers 11 is connected to the transmitter T1
and T2 and a plurality of acoustic transducers including three acoustic receivers R1, R2 and R3. Above the acoustic transducer are data from the acoustic transducer as well as a color detector 2.
1 and an acoustic cartridge 20 containing the necessary electronics to process the data from the gamma ray detector 22. Logging tool 10
The upper part contains a telemetry modem 23 that is used to transmit information to the surface and also serves as a receiver for transmitting control information to underground equipment.

The logging system consists of a properly programmed digital computer located on the ground.
It operates under the control of 0. Programs or instructions for the computer are initially stored on the tape transport 31 and loaded into the computer 30 when commanded from the terminal 32. The terminal device 32 includes a printer that serves as a monitor that monitors commands from the terminal device 32 to the computer 30 and allows an operator to ask questions to the computer 30. When the system is ready for operation, computer 30 connects bus 33, telemetry modem 34
and send commands to underground equipment via cable 15. Telemetry modem 23 within tool 10 provides control data or instructions to timing and controller 35 to establish conditions for particular tasks to be performed in sequence. For example, timing and controller 35 under computer command may cause transmitter _T1 to be energized by transmitter energizer 36 and conductor 37, or transmitter T2 to be energized by transmitter energizer 36 and conductor 38. Determine whether to energize by. Timing and controller 35 also instructs receiver selection and amplification means 40 to determine which receiver outputs to select and amplify. Now, the task to be accomplished is to provide a handshake or synchronization signal from the computer 30 to the timing and controller 35 by means of the telemetry modem 23 and conductor 41, and to adjust the peak or amplitude of the first half cycle of the casing signal appearing at the receiver. It is assumed that the cycle of the operating sequence including the measurement is to be started.

Although it is possible to create a conventional cement bond log using information about the amplitude of the signal traveling through the casing and received, the present invention uses computer processing of the amplitude information to determine the bond of cement to the casing. generate a decay rate log that more accurately represents the state or degree of . In a common cement bond log that plots the amplitude of the received signal as a function of depth, there are multiple conditions or factors that can affect the signal and tend to introduce errors in the resulting log. .
These conditions include receiver sensitivity, transmitter power, borehole temperature variations, drilling fluid conditions, formation hardness or velocity, and logging tool eccentricity.

The effects of these various parameters or conditions are:
The transmitter and receiver arrangement shown in FIGS. 1 and 2,
By using the method and apparatus of the present invention in combination with the physical relationship and the method and apparatus of the present invention, it is possible to significantly reduce or eliminate the physical relationship. For convenience, we will combine the damping due to the drilling fluid into a single damping coefficient M. This M shall also be valid for the lateral portions of the acoustic energy wave path between the casing and the respective transmitter and receiver. In FIG. 2, the combined attenuation coefficients between transmitters T1 and T2 and the casing are designated M1 and M4, and the attenuation coefficients M2 and M3 between receivers R1 and R2 and the casing.
It is shown. Coefficients M1, M2, M3 and M4
determines the ratio of the acoustic signal amplitudes received at each receiver from one transmitter and adds to this ratio the same obtained by comparing the acoustic signal amplitudes received at these receivers from the other transmitter. It can be removed by multiplying by such a ratio. The various acoustic signal amplitudes corresponding to each transmitter/receiver pair are T1R
1, T1R2, T2R1, T2R2.
C1 is the attenuation through the longitudinal zone between transmitter T1 and receiver R1, and C1 is the attenuation through the longitudinal zone between transmitter T1 and receiver R1, and transmitter T2 and receiver R
The transmissions between C2 and C2 are respectively indicated by C2. C3 is the desired attenuation function between the longitudinal zones between receivers R1 and R2. By relatively simple mathematical operations, the undesirable transfer or damping functions M1, M
It can be shown that by taking the ratio of the products of the amplitudes of the signals from these receivers, 2, M3 and M4, together with the damping functions C1 and C2, can be removed leaving only the desired damping function C3.

When investigating the media forming a cased wellbore, it is important to center the logging tool in the borehole. The reason for this is related to the length of the path that the acoustic energy has to travel between the acoustic transmitter and the receiver, and the amplitude of the casing signal that arrives first. Since the time taken for the acoustic energy to travel through the casing to the receiver is known, the gate can be opened at the appropriate time to measure the peak amplitude of the first energy (casing signal) reaching the receiver. This time and amplitude are determined for the case where the logging tool is in the center. If the logging tool is eccentric in the borehole, the energy emitted from one side of the tool will have a shorter path to and from the casing, causing the casing signal to reach the receiver sooner than expected. . The gates will therefore be offset in time and the measured casing signal amplitude will be low, causing errors in the cement bond log.

However, with the transducer geometry and operation shown in FIG. 2, problems induced by eccentricity are minimized because the same portion of the casing signal from all receivers is measured.

The determination of the attenuation factor according to the invention will now be explained with reference to FIG. The two transmitters T1 and T2 are arranged symmetrically with respect to the two receivers R1 and R2. The casing-propagating acoustic wave emitted by the upper transmitter T1 is attenuated at a distance d1 from the transmitter T1 and can be expressed by the following equation.

Here, A ₁₁ is the output of the receiver R1 (millivolts), P ₁ is the magnitude of the pressure for d1 = 0, S ₁ is the sensitivity of the receiver in millivolts/bar, and a is the attenuation rate of the acoustic signal. (decibel/foot). This relationship was established by Purdue et al. in the article "Cement Bond Log - A Study of Cement and Casing Variables" published on page 545 of the Journal of Petroleum Technology, May 1963. The output of receiver R2 can be expressed as:

Similarly, if the lower transmitter T2 is energized, the outputs of receivers R1 and R2 can be expressed as:

Using equations (1) to (4), the following ratios are obtained.

The relationship shown in equation (5) is called the BHC ratio.
From the BHC ratio ( _{5), the attenuation factor a can be determined by -10/d2-d1log10 [A12A21/A11A22 ] = a} (db/ _feet ) (6). It can be seen that the measured attenuation is independent of receiver sensitivity, transmitter power, and fluid attenuation during any sequence of operation.

The BHC decay measurement established by the present invention is
It has many advantages over the standard cement bond log measurement method, which can be summarized as follows. As is clear from FIG. 2, since the acoustic signals reaching R1 or R2 have traveled the same path through the casing fluid, their effects are removed when determining the amplitude ratio. Fluid damping effects can be important in heavy or gas cylinders. Transducer output typically decreases as temperature increases, and receiver sensitivity also decreases over time. This is a significant advance over previous systems since there is no need to constantly correct or calibrate the receiver output for changes in receiver sensitivity primarily due to temperature effects. These temperature effects are effectively counteracted by using ratio techniques. As mentioned above, BHC attenuation or ratio techniques are independent of the absolute value of the signal level. The value of the signal-to-noise ratio only limits the measurement range to 20 db/ft. Furthermore, eccentricity of up to 7.6 mm (0.3 inches) does not have a significant effect on the accuracy of the measurements.

It has been found that the spacing or physical distance between the transmitter and receiver is critical to obtaining accurate and reliable cement bond logs. If this interval is too long, the signal-to-noise ratio will be such that the casing signal is lost in the noise and cannot be detected. Even if the spacing is adjusted so that the casing signal can be detected, there are situations in which the detected signal does not represent the casing signal. This occurs when the velocity of the surrounding strata is higher than the velocity of sound passing through the casing, and when the distance between the transmitter and the receiver is large so that the strata signal appears at the receiver before the casing signal arrives. In this case, it will lead to an error in the measurement.

On the other hand, if the spacing between the receiver and transmitter is too close, errors will occur due to eccentricity induction errors. Therefore, the spacing between the transmitter and receiver is such that a measurable signal-to-noise ratio is obtained, the cement bond signal arrives before the formation signal arrives, and allows an eccentricity of up to 7.6 mm. should be selected accordingly. This state is transmitted from transmitter T1 to receiver R1.
Similarly, the distance from transmitter T2 to receiver R2 is approximately 73.15 cm (2.4 feet).
This is achieved by setting it to 73.15cm. Receiver R2 is approximately 103.63 cm (3.4 feet) from transmitter T1
receiver R1 should be separated from transmitter T2 by approximately
Should be 103.63cm apart. Receiver R3, which is used primarily to obtain variable density logs, is in one embodiment 5 feet away from transmitter T2.

Some examples in the prior art include acoustic logging systems consisting of a sonde with a pair of spaced apart receivers included between an upper receiver and a lower receiver; these systems do not measure formation parameters. It was configured to operate in an open (ie, uncased) wellbore for detection. These tools are somewhat related to the field of cement bond logging, which is based on the true nature of the signal being measured, namely the acoustic transit time. The distance between the receiver and the transmitter on the sonde is selected to maximize the travel time of the acoustic waves through the formation medium under investigation relative to the travel time of the acoustic waves between the sonde and the formation. . For this purpose, it is necessary to choose a relatively large spacing between receiver and transmitter. In contrast, with cement bond logging based on the principles of the present invention, the spacing between the transmitter and receiver is determined by the mixing output of the receiver and the cement bond, rather than increasing the travel time through the formation. They are selected to increase the correlation between them. Using a cased borehole with the spacing between the receiver and transmitter similar to that of an open hole logging tool means that, due to the nature of the measurement, the noise content of the signal in the cased hole will be higher than that between the receiver and the transmitter. This increases proportionally with the distance to the vessel, making it completely unsuitable for operation in systems for cased holes. The choice of spacing between transmitter and receiver is therefore a critical issue in realizing the advantages of the present invention.

Referring now to FIG. 1, a system for obtaining casing signal data used in the relationship defined by equation (6) will now be described. Commands from computer 30 to timing and controller 35 are followed by handshake or synchronization signals. Timing and controller 35 thereby sends an activation command to transmitter energizer 36 via conductor 42 to cause transmitter T1 to emit acoustic energy. The acoustic energy travels outward through the drilling fluid, refracts along the casing, and returns through the drilling fluid to receiver R1. The output of receiver R1 is applied through conductor 43 to receiver selection and amplification means 40, and the analog signal output from means 40 is applied to conductor 44, telemetry modem 23, cable 15 and telemetry modem 3.
4 to the monitor oscilloscope 50. The analog output from receiver selection and amplification means 40 is also applied to amplitude and transit time detection means 51 in which the peak amplitude of the casing signal is detected and the transit time of the signal is determined.

Typical waveforms of the casing signal reaching the receiver under different cement bond conditions are shown in FIG. If the casing is not bonded,
It will be seen that the half cycle of the waveform consisting of peaks E1, E2 and E3 is significantly larger than the amplitude of the corresponding peaks if the casing were fully bonded to the cement. The selection of the half-cycle in which the peak should be detected is at the discretion of the operator, since the travel time of the acoustic energy through the casing and the distance between the transmitter and the selected receiver are known.
Effective gate operation can be performed by the computer 30. This gating is effected by a timing and controller 35 which conditions the amplitude and travel time detection means 51 to measure the peak amplitude of the selected half cycle of the casing signal. become. Typically, the amplitude of peak E1 is detected.

Travel time detection or measurement is accomplished by control pulses applied from timing and controller 35 via conductor 54 to amplitude and travel time detection means 51. This control pulse signals the time when transmitter T1 is activated. Using conventional timing circuitry within the means 51, a digital signal is produced representing the value of the transit time for the acoustic energy to travel from the transmitter T1 to the receiver R1. This digital signal is applied directly to telemetry modem 23 through conductor 55 and transmitted to the earth's surface.

An analog signal representing the peak amplitude of the detected casing signal is applied through conductor 56 to a multiplex and A/D converter 60, the digital output of which is also applied to telemetry modem 23 for transmission to the surface.

The transit time signal is processed by computer 30, converted to an analog signal, and recorded as a function of depth by analog recorder 62 through conductor 61 at the option of the operator. This depth function is
As previously mentioned, the data are generated by conventional means, processed by computer 30, and used to displace data relative to the recording medium. A digital representation of the amplitude of the detected casing signal is temporarily stored in computer 30 for use, along with other data, in generating a signal representative of the attenuation rate according to the present invention.

Once the system has completed the first cycle of the sequence, computer 30 sends another command to timing and controller 35 as described above to again energize transmitter T1, this time transmitting the output of receiver R2 to receiver T1. It is connected to selection and amplification means 40. In this case too, the amplitude of the housing signal reaching the receiver R2 is detected and the travel time of this signal between the transmitter T1 and the receiver R2 is measured. The transit time can be recorded as a function of depth on an analog recorder 62, and the digital value of the amplitude of the received casing signal is also stored in the computer 30.

In the next cycle of the sequence, commands are transmitted from computer 30 to timing and controller 35 to establish the conditions for firing transmitter T2 and connecting receiver R2. Upon handshaking by conductor 41, transmitter T2 fires and acoustic energy traveling through the casing is detected at receiver R2. Peak amplitude E1 of the first half cycle
is detected by amplitude detector 51 and connected to multiplex and A/D converter 6 through conductor 56.
0 and is converted into a digital signal. This digital signal is sent to the computer 30,
be remembered. The transit time of the energy between transmitter T1 and receiver R2 is also measured and transmitted to the earth's surface.

When another command and then a handshake signal are transmitted from the computer 30, the transmitter T2 fires again and the energy received by the receiver R1 through the casing is transmitted through the conductor 43 to the receiver selection and amplification means 40. supplied to An analog representation of this signal is also transmitted through conductor 44 and telemetry modem 23 to a ground-based monitor oscilloscope 50. As previously described, the amplitude of the first half cycle of energy arriving through the casing is detected and provided to multiplex and A/D converter 60 for transmission to computer 30;
A digital representation of the detected travel time is sent from the amplitude and travel time detection means 51 via conductor 55 and telemetry modem 23 to computer 30 and recorded on analog recorder 62, if desired.

Now, in the final stage of the sequence associated with the generation of acoustic energy and its detection after traveling through the casing, the transmitter T2 is energized again and the output of the receiver R3 is transferred to the conductor 65, the receiver selection and amplification means 40 and the conductor 44. is applied to the telemetry modem 23 via. The signal or waveform train from receiver R3 is used to create a variable density log in a known manner.

Recorder 62 consists of an oscilloscope and photographic film. By sweeping an electron beam across the face of the oscilloscope, modulating the beam intensity with the received acoustic energy waveform, and moving the film through the face of the oscilloscope as a function of the depth of the logging tool. A log is created. A typical variable density log is a U.S. patent
It is shown in Figure 4 of No. 3696884.

Above, T1, R1, T1, R2, T2, R2,
The operational sequence consisting of five cycles of acoustic detection, T2, R1 and T2, R3, is completed. Each cycle requires the transmission of control information and a subsequent handshake from the computer 30 to the underground equipment. Handshake is a synchronization signal that notifies underground equipment of command execution. After collecting the casing signal amplitude for each sequence, computer 30 generates an attenuation rate signal a according to the relationship defined by equation (6), which signal is transmitted to the recorder as a function of the depth of the logging tool. Recorded by 62.

The underground tool also includes a color detector 21 and a natural gamma ray detector 22. The outputs of these detectors are multiplexed and A/D converter 60 under the control of timing and controller 35.
is connected to via a conductor 70. Digital representations of these signals that trigger the 5-cycle acoustic mode of operation are sent through telemetry modem 23 and cable 15 to computer 30, where they are processed and recorded by analog recorder 62 as a function of depth. recorded. Natural gamma ray and color detector parameters are useful in correlating the obtained cement bond log with other logs previously obtained in the open hole.

In the system shown in FIG.
2 is 4 for each sequence of casing signal amplitude measurement.
energized twice. The continuous firing range of transmitter T1 is such that the output of either transmitter may change during the continuous firing of transmitter T2. In this case, errors are likely to be introduced into the ratio determination. This error due to sudden changes in the transmitter output can be avoided by the method of generating a signal from the receivers R1 and R2 for each firing of the transmitter T1. That is, each time the transmitter T2 fires, a similar signal is obtained from the receivers R2 and R1. The system of FIG. 1 is modified to include second amplitude and transit time detection means similar to means 51. In this way, each time the transmitter fires, there are two receiver signals to be used in the ratio relationship, thus avoiding introducing errors no matter how the transmitter output changes. .

Recall that the system of FIG. 1 determines and records the acoustic transit time between transmitter and receiver. Running time is 30.48cm (1
In strata below 57 microseconds per foot,
The 103.63 cm (3.4 ft) width measurement is meaningless. In fact, no measurements are taken at a transmitter-to-receiver spacing of 3 feet. Under these conditions, the formation signal running behind the cement sheath precedes and becomes itself superimposed on the casing running signal. Therefore, with such transducer spacing, it is impossible to measure the attenuation rate due to the casing segment bond.

Shorter transducer spacing appears to make it easier to measure attenuation rates in environments with hard or high-velocity formations. However, shortening the spacing introduces errors due to eccentricity. The shorter the distance between T and R, the more pronounced the eccentricity effect becomes.

Attenuation rate measurements are impractical under these high-velocity formation conditions, so rather than stop data collection, we continue to use the physical location from receiver R3 to obtain some measure of cement bond condition. That's what I do. Receiver R3 is 152.4 cm (5 feet) from transmitter T2 for the purpose of obtaining standard variable density logs.
It is located at. This is receiver R3
will be approximately 0.8 feet from transmitter T1. We have found that with this spacing, the first signal to arrive is the casing signal even when formation travel times are as low as 47 microseconds/foot.

During the logging operation, the operator selects the
Let us observe the value of the transit time between the receiver pair. If the observed travel time falls below the travel time of the acoustic energy within the casing, the computer 30 is commanded via the terminal 32 to change the sequence of underground operations. This causes receiver R3 to respond to acoustic energy from transmitter T1.
The peak of the first half cycle of the signal from is detected by the amplitude detection means 51 and the system operation will be modified to obtain a common cement bond log as recorded by the recorder 62.

If the above operations are performed to obtain a common cement bond log, variations in the transmitter output create problems. According to another aspect of the invention, errors caused by variations in transmitter output are avoided. That is, the receiver output is changed as a function of the transmitter output.

The underground system includes a transmitter energy detector that generates a measure of the energy produced by transmitters T1 and T2 each time they are energized.
This measurement is performed by means of a voltage applied to the transmitter by the transmitter 36. For example, a typical voltage applied to each transmitter is approximately 1500 volts. If the voltage output of the energizer were to change and drop to 750 volts while transmitter T1 was continuously energized, the detected peak amplitude of the received signal would also drop and cause an error. become.

A measure of the transmitter voltage (TV) is the transmitter energizer 36
and is applied to multiplex and A/D converter 60 by conductor 75. The digital value of the measured transmitter voltage is sent to the computer 30.
is used according to the following formula:

A′13=A13/G×1500/TV (7) where A′13 is the amplitude of the signal used for recording or otherwise, A13 is the amplitude of the measured signal, and G
is the gain of the amplification means 40.

By modifying the receiver signal as a function of transmitter voltage as described above, more accurate common type cement bond logs can be obtained, and such modifications can be applied to systems other than those shown in Figure 1. It is also available. It is also useful for ratio methods where the transmitter voltage may vary between successive firings of any transmitter. Therefore, the system of Fig. 1 also detects the value of the transmitter voltage each time the transmitters T1 and T2 emit, and calculates each received signal by a coefficient consisting of the ratio of the predetermined transmitter voltage and the measured transmitter voltage. It is operated so that it changes accordingly.

The foregoing discussion has concerned eccentricity and the problems introduced when eccentricity becomes significant. The system is capable of producing accurate attenuation rate logs with eccentricities as large as 7.62 mm (0.3 inches). If this limit is maintained, problems will arise in diagonal wells with an inclination of more than 20 degrees. In these cases,
The weight of the logging tool is increasingly applied to the centerer, causing the tool to move from a centered position to a position closer to the casing. This eccentricity problem can be substantially reduced by utilizing the logging tool of FIG. According to this array,
It is possible to maintain the tool within 7.62mm of the casing axis even with well slopes as large as 90 degrees. The lower part 80 of the tool houses transmitters T1 and T2 and receivers R1, R2 and R3. This lower part 80 has in-line centerers 81 and 82 with wheels 84 and 83, respectively, to facilitate passing the tool along the casing.
is maintained in the center of the casing by

The lower part 80 is essentially and naturally arranged even when this part is in a horizontal position, i.e. when the slope of the well is
Even at 90 degrees, the centering devices 81 and 82 are made sufficiently light so as not to be significantly compressed. This light weight is maintained by effectively mechanically decoupling the lower portion 80 from the rest of the logging tool. This decoupling is provided by two flexible joints 91 and 92 located between the cartridge 90 and the lower part 80. The articulation provided by these flexible joints frees the lower portion 80 from lateral movement of the cartridge 90 and other upper portions of the logging tool due to forces including gravity.

This cement bond tool is a logging tool with a size of 69.85 mm (2 3/4 inches) and a temperature of 176.7℃ (350℃).
〓), rated at 1476.5Kg/cm ² (21000p.si).
The part of the tool that houses the transducer is light and sturdy, weighing approximately 45 kg (100 lbs). The optimum transmitter-receiver spacing was set at 73.15 cm (2.4 feet) and 103.63 cm (3.4 feet) for the near and far receivers, respectively.
Another receiver was set 5 feet from the lower transmitter to generate data for the variable density log. This other receiver is connected to the upper transmitter.
24.38cm apart and provides data for common cement bond logs when logging through high velocity formations. The computer used in the first embodiment is a PDP1134.

Now, Figure 5 shows the BHC obtained by the present invention.
Examples of attenuation logs, as well as natural gamma logs, color locator logs, and travel time logs are shown.
The travel time log shows that the values are sufficiently constant to indicate that the detected signal traveled within the casing. Not unexpected in the trip time log were sudden changes due to malfunctions, commonly known as cycle skipping. This attenuation rate log is 395m (1296 feet)
It shows a very low attenuation rate indicating a weak cement bond at a depth of . Any scale above 10 db/ft indicates a good cement bond. Values below 10 db/ft may be acceptable and should certainly raise questions regarding the capabilities of the cement bond.

Although the preferred embodiments of the present invention have been described above,
It should be understood that various changes and modifications can be made without departing from the scope of the invention.

[Brief explanation of drawings]

FIG. 1 shows an embodiment of a logging system using the principles of the present invention in the form of a block.
FIG. 2 is an enlarged view of a portion of FIG. 1 showing the acoustic wave path through the drilling fluid and casing, and FIG. 3 shows the acoustic wave path through the cemented casing under different cement bond conditions. Figure 4 shows the shape of the traveling acoustic signal, Figure 4 shows the deformation of the underground sonde that minimizes the eccentricity even when the well slope is large, and Figure 5 2 is a diagram illustrating a typical cement bond decay rate log made, along with other types of logs made using the system of FIG. 1; FIG. 10...Logging tool, 11...Centering device, 12
...Borehole, 13...Fluid, 15...Cable, 2
0...Acoustic cartridge, 21...Color detector, 2
2... Gamma ray detector, 23, 34... Telemetry modem, 30... Digital computer, 31... Tape transport, 32... Terminal, 33... Bus, 35... Timing and controller, 36... Transmitter energizer, 37, 38, 41, 42, 43, 44,
54, 55, 56, 61, 65, 70, 75...Conductor, 40...Receiver selection and amplification means, 50...Monitor oscilloscope, 51...Amplitude and transit time detection means, 60...Multiplex and A/ D converter, 62... Analog recorder, 80... Tool lower part, 81, 82... In-line centering device, 8
3,84...Wheel, 90...Cartridge, 91,9
2...Flexible joint, T...Acoustic transmitter, R...Acoustic receiver.

Claims (1)

[Claims] 1. Two acoustic transmitters spaced apart in the vertical direction;
If a measurable signal-to-noise ratio is obtained and the casing signal arrives before the formation signal arrives, 7.62
Prepare a well tool with two acoustic receivers spaced vertically between the acoustic transmitters and the transmitter-receiver spacing to allow an eccentricity equal to mm (0.3 inches). moving the tool through the borehole and repeatedly energizing said acoustic transmitters to apply acoustic energy to a casing surrounding the well tool and transmitting acoustic energy from a first of said transmitters to a casing surrounding said well tool; detecting in a receiver the acoustic energy reaching said receiver via a second transmitter of said transmitter through a casing, following energization of said first transmitter; an acoustic casing selected on the basis of the first expected arrival of acoustic energy at each receiver; measuring the peak amplitude of a portion of the signal; determining the ratio of the peak amplitudes measured at each receiver relative to the activation of said first transmitter; and determining the ratio of the peak amplitudes measured at each receiver relative to said activation of said second transmitter; determine the ratio of the peak amplitudes measured at each receiver, multiply these ratios to generate a function representing the attenuation of acoustic energy through the casing, and record that attenuation as a function of tool position within the borehole. A method for measuring the degree of adhesion of cement to a casing in a borehole, comprising steps. 2. The method of claim 1, wherein each transmitter is energized twice to generate four acoustic pulses, and the peak amplitudes of the four resulting casing signals are detected by the receiver. 3. Activating each transmitter once to generate two acoustic pulses, and each resulting casing signal being detected by both receivers.
The method described in. 4 energize the transmitter by applying an energizing voltage, measure the value of the energizing voltage, compare this measured value with a predetermined value of voltage to generate a modification function, and apply this modification function to the transmitter. 3. A method as claimed in claim 2, in which variations in the value of the energizing voltage are corrected in addition to the peak amplitude of the casing signal resulting from the energizing. 5. The method of claim 4, wherein the modification function is a ratio of a predetermined value of voltage to a measured value of energizing voltage. 5. The well tool includes a third acoustic receiver between the first transmitter and an adjacent receiver, the transmitter and at least one receiver of the receivers other than the third acoustic receiver; measure the transit time of the acoustic energy through the casing, compare this measured transit time with the known transit time of the acoustic energy through the casing, and determine that the measured transit time decreases to a predetermined value that is less than the known transit time. detecting the peak amplitude of the first half cycle of acoustic energy present at said third receiver upon excitation of the first transmitter, and recording this peak amplitude as a function of tool position within the borehole. 2. The method of claim 1, further comprising the steps of: 7. The method of claim 6, wherein the predetermined value is 57 microseconds/foot. 8 applying an energizing voltage to excite the first transmitter;
The value of this energizing voltage is measured, this measured value is compared with a predetermined voltage value to generate a modification function, and this modification function is applied to the peak amplitude to correct for variations in the energizing voltage value. A method as claimed in claim 6, also comprising the steps. 9 Two vertically spaced acoustic transmitters with vertical spacing between the acoustic transmitters approximately 2.4 feet (73.15 cm) and 3.4 feet (103.63 cm) from each transmitter, respectively. a well tool having at least two acoustic receivers disposed in the well tool; means for repeatedly energizing an acoustic transmitter to deliver acoustic energy into a casing surrounding the well tool; detecting energy reaching the receiver through the casing from a first transmitter in said transmitter and energy reaching through the casing from a second transmitter in said transmitter following energization of the first transmitter; means for measuring the peak amplitude of the selected acoustic portion on the basis of the expected first arrival of acoustic energy at each receiver; upon energization of the first transmitter; means for determining the ratio of the peak amplitudes measured at each receiver upon energization of the second transmitter; means for determining the ratio of the peak amplitudes measured at each receiver upon energization of the second transmitter; Measuring the degree of adhesion of cement to a casing in a borehole, comprising: means for generating a function representative of the attenuation of acoustic energy; and means for recording the rate of attenuation as a function of tool position within the borehole. Device. 10 a third receiver located between one of the transmitters and one of the at least two spaced transmitters, measuring the transit time of acoustic energy reaching at least one of said receivers; means for comparing this measured transit time with a known transit time of acoustic energy through the casing under investigation; if said measured transit time falls below the value of said known transit time; means for obtaining the peak amplitude of the first half-cycle of acoustic energy appearing at said third receiver following energization of said third transmitter; and means for recording said peak amplitude as a function of tool position within the borehole. 10. A device according to claim 9 comprising: 11 The third receiver is approximately
24.38cm (0.8 ft) approximately from the other transmitter
11. The apparatus of claim 10, wherein the apparatus is located at 5 feet. 12 generating an acoustic signal at a first location within the borehole; generating an acoustic signal at a second location within the borehole; a third location in the borehole separated from the first acoustic signal generation location by a selected spacing such that the cement bond signal through the casing reaches the location; and a fourth location in the borehole separated from the second acoustic signal generation location. the ratio of the peak amplitudes of the acoustic signals from the first and second acoustic signal generation positions detected at the third acoustic signal detection position;
Determining the attenuation between the third and fourth acoustic signal detection positions from the product of the peak amplitude ratio of the acoustic signals from the first and second acoustic signal generation positions detected at the fourth acoustic signal detection position, A method for measuring the degree of adhesion of cement to a casing in a borehole, the method comprising measuring the degree of adhesion of cement to a casing in a borehole. 13. The method of claim 12, wherein the selected spacing is less than or equal to 3 feet and the spacing between the third and fourth acoustic signal detection locations is about 1 foot. 14. The method of claim 12, wherein the generation of the acoustic signals from the first and second locations is not simultaneous. 15 detecting at a third location a reflected portion of the acoustic signal propagated from one of the signal generating locations and extracting from said reflected portion an indication of the properties of the formation surrounding the casing; The method according to claim 12. 16 detecting a reflected portion of the acoustic signal propagated from the signal generation position at a third position between one of the signal detection positions and the signal generation position closest to the signal detection position; The method according to claim 12, wherein the degree of adhesion of the cement to the casing is determined from the reflected portion received at the position. 17. At a third location, detecting reflected portions of the acoustic signal propagated from the other of the signal generation locations, and deriving from these reflected portions an indication of the properties of the formation surrounding the casing.
The method described in. 18 a long support, on which a first and second
acoustic signal generating means, said first and second acoustic signal generating means separated from each other by a distance which ensures reception of the casing signal before the arrival of the formation signal; first and second acoustic signal detection means arranged on the support body apart from the signal generation means; and the first and second acoustic signal generation means generate and detect the first acoustic signal. the product of the ratio of the amplitudes of the acoustic signals detected by the means and the ratio of the amplitudes of the acoustic signals generated by the first and second acoustic signal generating means and detected by the second acoustic signal detecting means; 1. A device for measuring the degree of adhesion of cement to a casing in a borehole, comprising means for measuring the degree of adhesion of cement to a casing in a borehole by determining the attenuation of an acoustic signal generated between detection positions. 19. The distance to ensure reception of the casing signal prior to the arrival of the formation signal is less than or equal to 3 feet, and the spacing between the two detection locations is approximately 30.48 cm (3 feet) or less.
19. The apparatus of claim 18, which is 1 foot. 20. Apparatus according to claim 18, in which the first and second sound generating means are not energized simultaneously. 21 third acoustic signal detection means arranged on the support and detecting the acoustic signal sent from one of the acoustic signal generation means; 19. The apparatus of claim 18, further comprising means for retrieving an indication representative of the characteristic. 22. A third acoustic signal detecting means arranged on the support and detecting an acoustic signal between one of the acoustic signal generating means and the nearest acoustic signal detecting means; and this third acoustic signal detecting means. 19. The apparatus according to claim 18, further comprising means for determining the degree of adhesion of cement to the casing from the output of the means. 23. The apparatus of claim 22, further comprising means for deriving support for characteristics of the formation surrounding the casing from the output of the third acoustic detection means. 24 The distance between the two acoustic signal detection means is approximately 30.48
22. The apparatus of claim 21, wherein the distance between the third acoustic signal detection means and one of the acoustic signal generating means is about 5 feet.