Untitled record

Full description

Sister Ar'a's background

In the process of exploring for hydrocarbons reservoirs, companies use several data collection techniques, such as recording well logging performance. During the well drilling process, or shortly thereafter, drillers pass drilling recording equipment through the drill hole to collect

<p dir="rtl">5 Information regarding surrounding formations. The information is traditionally compiled in the form of a “log”, i.e., a table, chart or graph of measured data values as a function of position along the drill hole. When position information for drilling performance recording equipment includes both depth and direction, the record can take the form of a 2D "image" of the drill hole wall. Imaging allows analysts to study the fine-scale structure of penetrated formations, which include stratifications,</p>

<p dir="rtl">10 Fractures, dip angles, rock texture, vugs, and other rift features. Image recording can be done, for example, by wireline logging or logging-while-drilling.</p>

(LWD).

In recording the performance of the drilling cable, a probe is inserted into the drill hole after some or all of the well has been drilled. 15 The probe is suspended from the end of a long cable (“wireline”) which provides mechanical support and an electrical connection between the probe and the drilling performance recording equipment placed on the surface of the well. According to existing performance recording techniques, several ground formation variables are measured and linked to the position of the probe in Drilling Hole When the probe is pulled up the well in LWD, the drilling assembly includes sensors that measure several variables as the formation is penetrated. While LWD technologies allow

<p dir="rtl">20 With more contemporary formation measurements, drilling operations create a generally harsh environment for electronic instrumentation and sensor operations.</p>

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Different types of drilling performance recording information are required to include, among other things, formation density, formation resistivity, acoustic velocity, pore volume, and pore pressure. Formation intensity is commonly measured by measuring the attenuation and/or scattering of nuclear radiation from a source

<p dir="rtl">5 radioactive source ) Return, for example, Well Logging for Earth</p>

Scientists, 2d by Darwin Ellis and Julian Singer, © 2007 Springer, ISBN

978-1-4020-3738-2). Accordingly, obtaining these records may require the transfer, dissemination, and use of radioactive material, with a corresponding allocation of resources for safety and protection. Another formation density measurement technique uses a nuclear magnetic resonance (NMR) instrument. resonance(

<p dir="rtl">10 To indirectly estimate the formation porosity, which in turn is reciprocally related to the formation density provided that the matrix grain density is known.</p>

Another measurement of interest in oil and gas well construction is the acoustic impedance at the outer surface of the casing. For well control and zonal isolation requirements there are situations where casing must be well bonded to the cement casing. Shows the interface between the casing

<p dir="rtl">15 In this case, cement has a significantly higher acoustic impedance than when the outer surface of the packaging is simply in contact with the gas or liquid. The acoustic impedance measurement is then interpreted directly as a cement bond quality record (see, for example, US Patent No. 4,255,798, issued on 10</p>

R. M. Havera, “Ultrasonic Cement Bond Evaluation”, Paper N, March 1981, and

SPWLA Symposium 1982 20

US Patent No. 20030042018 is generally related to the field of oil production. In particular, it relates to a method of improving oil recovery, preferably heavy oil, by accelerating drainage by gravity using vibration energy generated by a well fracture.

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US Patent No. 20140169127 relates to the study of subterranean formations and formations, for example, as well as to oil and gas exploration. In particular, it relates to seismic surveying, including formal techniques for depicting the boundaries of the layers of subterranean geological formations around the wellbore.

General description of the invention

<p dir="rtl">5 One embodiment of the present invention relates to a method, including:</p>

Place an acoustic transducer at the bottom of the well in a manner largely parallel to the wall of the drill hole. Accordingly, a fluid layer is created between the wall and the acoustic transducer, and an acoustic impedance is measured at the surface of the acoustic transducer at the resonance frequency of the fluid layer. Accordingly, the acoustic impedance of the formation is determined. .

<p dir="rtl">10 Another embodiment of aspects of the present invention relates to a system, including:</p>

An acoustic drilling logger extending the length of a drill hole through a formation wherein the acoustic drilling logger includes an acoustic transducer positioned substantially parallel to the wall of the drill hole, whereby a fluid layer is created between the wall and the acoustic transducer, and wherein the acoustic drilling logger measures the acoustic impedance of the transducer sound at the resonant frequency of the fluid layer; A processor coupled with a tool

<p dir="rtl">15 Acoustic drilling performance recording, which receives acoustic impedance measurements and determines an acoustic impedance of the formation based on it.</p>

Brief explanation of the drawings

Accordingly, drilling performance recording systems, tools, and methods for measuring acoustic impedance and formation density are disclosed herein. In graphics:

<p dir="rtl">20 Figure 1 is an illustrative LWD (logging-while-drilling) environment.</p>

Figure 2 is an illustration of a borehole wall image.

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Figure 3 is a cross-sectional projection of an illustrative LWD imager.

Figure 4 is an enlarged cross-sectional view of an illustrative acoustic transducer for measuring resonant acoustic impedances.

Figure 5 is an illustrative graph of audio impedance versus frequency.

<p dir="rtl">5 Figure 6 is a side view of an illustrative LWD imager measuring the sound wave velocity of the formation.</p>

Figure 7 shows the tool in Figure 6 measuring the speed of sound wave propagation in the wall of the drill hole.

Figure 8 is a functional block diagram of the electronics of an illustrative instrument.

<p dir="rtl">10 Figure 9 is a flowchart of an illustrative method for measuring acoustic intensity.</p>

Figure 10 is a block diagram of an illustrative computer system.

However, you should understand that the specific embodiments set forth in the drawings and detailed descriptions thereof do not limit the disclosure. On the contrary, it provides the basis for one with ordinary skill to perceive the alternative images, equivalents, and modifications involved with one or more embodiments in a field.

<p dir="rtl">15 Accessory protection elements.</p>

Detailed description:

Disclosed here are systems and methods for measuring acoustic impedance and formation density. Embodiments of a particular method include placing an acoustic transducer downhole substantially parallel to the wall of the drill hole, thereby creating a fluid layer between the wall and

<p dir="rtl">20 And the acoustic transducer, measuring the acoustic impedance at the surface of the acoustic transducer at the resonance frequency of the fluid layer, and accordingly the acoustic impedance of the formation is determined. The audio transformer may include a speaker coil, a plate mounted on</p>

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The outer part of the aforementioned transformer, and a stress sensor placed between them. The transformer may also include a displacement sensor to measure the amplitude and displacement of the face of the transformer. The combined knowledge of the transducer face stress and the transducer face displacement capacity produces a direct estimate of the transducer face acoustic impedance. The position and direction of the transducer can be tracked to determine the acoustic impedance estimate within the borehole wall image.

The disclosed instruments and methods may further include (or may be combined with separate instruments containing) sensors for measuring acoustic wave velocities in the formation as a function of position and direction. Acoustic impedance estimates may be divided by acoustic wave velocity measurements to obtain the formation density. (Dividing by the speed of the sound wave can be considered equivalent to multiplying by 10 by the slowing down of the sound wave.)

Embodiments of the tool and method disclosed can be better understood in the context of use. Thus, Figure 1 shows an illustrative environment for logging while LWD drilling. The 2 drilling platform is equipped with 4 derrick cranes supporting a 6 hoist jack. Drilling equipment operators drill oil and gas wells using a series of 15 Drill pipes are coupled together and form a drill string 8 that suspends the hoisting machine 6

A top drive 10 works to rotate the drill string 8 and remove the drill string 8 through the wellhead 12 and into the formation 30. A drill bit 14 is connected to the lower end of the drill pipe string 8. Drilling is accomplished by rotating the drill bit 14 and the drill pipe string 8, using a motor close to the drill bit, or by both

<p dir="rtl">20 Both ways. The mud recirculation equipment 16 pumps drilling fluid through a supply pipe 18, through a top drive 10, and down through a string of drill pipes 8 at high pressures and volumes so that it emerges through nozzles or nozzles in the drill bit 14. After This moves the mud back up the hole through the annular space 32 annulus formed between the outside of the drill pipe string 8 and the hole wall.</p>

<p dir="rtl">25 Drilling 20 borehole wall, through the surge preventer, and inside a mud pit 22 mud pit on</p>

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Surface. At the surface, the drilling mud is cleaned and then recycled by recycling equipment 16. Drilling mud is used to cool the drill bit 14, to carry drilling extractives from the base of the hole to the surface, and to equalize hydrostatic pressure in rock formations.

<p dir="rtl">5 The bottom hole assembly (i.e., the lowest part of a string of 8 drill pipes) includes thick-walled tubular elements (called drill collars) to add weight and rigidity to aid in the drilling process. The thick walls of these drill collars are useful for housing rigs LWD measurement and sensor. Thus, for example, the downhole assembly of Figure 1 may include a micro-sonic imaging tool 24 which 10 contains one or more acoustic transducers for measuring sound wave velocities in the formation, a separate echo-impedance sensor 26 separate resonant impedance sensor to estimate the acoustic impedance of the composition, a position and orientation measuring instrument 28, and a telemetry module 30. Other tools and sensors can be included in the downhole assembly to collect measurements of many drilling variables such as weight on the bit, drill hole diameter, and so on. 15. The direction of the tool can be determined in terms of the angles of the tool surface (direction of rotation), angles of inclination (inclination), and the direction of</p>

compass, each of which can be derived from measurements made with magnetometers, inclinometers, accelerometers, gyroscopes, and the like.

As the drill bit extends the drill hole through subterranean formations, the micro-sonic imaging tool 24 rotates and collects sound wave velocity measurements 20 which the downhole controller correlates with the position and direction of the tool to obtain a velocity image map of the drill hole wall. Similarly, the resonant 26 impedance sensor rotates and collects acoustic impedance measurements that the downhole controller links to the tool position and orientation to obtain an acoustic impedance image map of the drill hole wall. (The principles of operation of said instruments are discussed in more detail below.) The control module 25 and telemetry 30 collect measurement data and signals from instruments 24, 26, 28, and measuring devices

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other downhole assembly and stores it in internal memory. Selected pieces of data can be communicated to the surface by, for example, a clay pulse telemeter. There are other methods for measuring and recording drilling performance during remote drilling that can be used. As a specific example, drill pipe series 8 may be formed from a wired drill pipe that enables wave images or images to be transmitted to

<p dir="rtl">5 The surface is real-time to allow quality and processing monitoring to improve the accuracy of recording drilling performance.</p>

For a mud pulse telemetry method, the telemetry module 30 modulates resistance to a drilling fluid flow to produce pressure pulses that propagate to the surface. One or more pressure transducers 34, 36 (isolated from the mud pump noise 16 by a desurger 40) convert the pressure signal into an electrical signal (signal) to a signal digitizer 10 38 digitizer. The digitizer 38 supplies a digital image of the signals Compression to computer 50 or image

Other means of processing data. The computer 50 operates according to a program (which may be stored on non-transitory information storage media).

<p dir="rtl">52 storage media) and user input received via an input medium 54 to process and decode the received signals. The resulting telemetry data can be analyzed and processed by the computer 50</p>

<p dir="rtl">15 To produce a display of useful information on a computer screen 56 or other image of a display medium. For example, an operator may use this system to obtain and view an audio impedance log and, at least in some cases, a composition density log. Either record can be displayed as a drill hole wall, or as an average impedance/density value versus position.</p>

Figure 2 shows an illustrative borehole wall image 122 that is obtained when composition measurements (such as sound wave speed, acoustic impedance, or density) are correlated.

With tool position L and rotational direction b. The drill hole wall surface is divided into “boxes”, where each box represents a pair of values of tool position L and rotational direction b. Each time the sensing surface passes a block, it collects one or more measurements that can be combined with previous measurements of that block. The combined measurements can then be processed (as discussed in more detail below)25 to obtain an intensity estimate which can be displayed as pixel color and/or pixel intensity. Typically

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These images reveal stratigraphic structures (eg. 124 structures) and faults (eg

Fault 126 (fracture). These features usually show a sinusoidal dependence on rotational angles, indicating

The drill hole is exposed to the aforementioned feature at angles other than 90 degrees. It is noted that these features usually appear even if density measurements are only relative in nature and not precisely precise. Complete

<p dir="rtl">5 Image resolution is largely determined by the measurement accuracy of the sensing surface, which depends on the size, distance, and spacing of the acoustic transducers.</p>

Figure 3 shows a cross section of an illustrative LWD embodiment of a re-echoing impedance sensor 26 in a drill hole 20. The impedance sensor 26 shown includes three counterbalancing blades 130, 132, 134 to keep the tool centered. The exact formation and number of vanes can vary

<p dir="rtl">10 The budget is based on the expected drilling environment and is generally expected to increase as the drill hole diameter increases.</p>

The tool includes 26 acoustic transducers 136 placed between stabilizer blades 132, 134. An enlarged scale cross-sectional projection is shown in Figure 4. As shown, the audio transducer 136 includes a magnetic holder

<p dir="rtl">15 300 cradle placed inside a wall 204 wall A tool for recording the performance of sonic drilling 24. It is done with a stand</p>

300 Installing a “speaker coil” assembly (for example, an electromagnetic solenoid).

302 )electromagnetic solenoid and plate 304 having a surface 305 that is oriented substantially parallel to the wall of the drill hole 20. A piezoelectric strain sensor may be located

302 The speaker coil assembly 306 board is between the speaker coil assembly and the stress sensor

<p dir="rtl">20 304 To measure the force (and therefore dynamic pressure) exerted on a surface 305.</p>

Other strain sensor technologies are also known and can be used. The speaker coil assembly 302 can emit a narrowband audio output signal 314 that is scanned over a range of frequencies (e.g., 10 kHz to 120 kHz), or alternatively a broadband signal. The plate 304 is preferably thin (e.g., 10 kHz to 120 kHz). While still thick enough to be solid(

<p dir="rtl">25 The surface 305 is in direct contact with the fluid 200 in the annular space 32.</p>

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In addition to the pressure measurement obtained via the stress sensor 306, the acoustic transducer is equipped with a motion sensor (shown in Figure 4 as an optical fiber 308 transmitting a light beam to and from the speaker coil assembly 302) to measure the oscillatory displacement or plate velocity 304 The aforementioned motion sensor could, for example, be an interferometer

<p dir="rtl">5 Laser, high-precision accelerometer, or auxiliary solenoid. Alternatively, the movement of plate 304 may be obtained indirectly by measuring the load current or electrical impedance of the speaker coil. Whether the measurements are of surface pressure, surface velocity, or some other characteristic of the transducer, they should preferably be sufficient to obtain a determination of the acoustic impedance provided at the transducer's surface at any given frequency.</p>

<p dir="rtl">10 The speaker coil assembly 302 , strain sensor 306 , and motion sensor 308 may be coupled to, and controlled by, an instrument control means or other image of a processor that executes a firmware or stored program to estimate the acoustic impedance of the configuration. Under software control, the instrument control means causes the audio transducer 136 to produce audio signals using the audio transducer 300, obtain measurements representing its audio impedance, and rely on them to determine its impedance.</p>

<p dir="rtl">15 Genesis. The instrument control may store the formation impedance as a function of position and direction, and may also communicate (via a telemetry system) at least some of the measurements to the surface for display.</p>

In an illustrative process, the tool control actuates the coil assembly 302, causing the plate 304 to oscillate and thereby emitting an acoustic signal 314 toward the formation. 20 The audio signal 314 can be a narrowband signal produced at a frequency of CAN

Controlled or cleared, or alternatively it can be a wideband signal. The audio signal 314 propagates from the surface 305, through the fluid layer 200, reaches the formation wall 20, and is reflected (at least partially) from it to obtain a reflected signal 316. The reflected signal returns through the fluid layer 200 to reach the plate 304, and is partially reflected from it at

<p dir="rtl">25 the least. The acoustic signals 314, 316 cause vibration of the fluid layer, depending on the intensity of the vibration, from</p>

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Among other things, on the frequency of the audio signal. As shown in Figure 5, the acoustic impedance602 of the operating surface 305 similarly depends on the frequency of the acoustic signal, which peaks 604 at the resonating frequency of the fluid layer. (The acoustic impedance of the operating surface 305 is expressed as the surface pressure ratio

<p dir="rtl">5 305 to the surface speed of 305. The amplitude of the resonance peak is 604 mentioned</p>

Corresponding to the acoustic impedance of the configuration. Theoretically, the peak acoustic impedance is equal to the acoustic impedance of the formation, but when curvature and curvature of the surface 305, curvature of the wall of the formation 20, and non-ideal conditions of the actuation and sensing circuits are determined, a calibration factor may be needed to match the peak value to the acoustic impedance of the formation. A calibration factor can also allow the use of properties

<p dir="rtl">10 Other transducers (e.g., displacement, acceleration, force, reverse EMF) to measure acoustic impedance.</p>

To achieve greater signal strength without suffering penalties associated with added mass and plate flex 304, the impedance sensor can include a plurality of said transducers 136 that are positioned contiguously along a line or across an area. In addition to increasing the operating surface area, it can be operated

<p dir="rtl">15 Different audio transformers use a stepwise manner to focus the signal or at least partially compensate for the "fringe" or "edge" effect that can result from signal diffraction and scattering. In addition, the aforementioned array formation can improve the spatial resolution of measurements, which is beneficial in producing drill hole wall images.</p>

Figure 6 shows a side view of a microsound wave imager 24 to measure wave velocity

<p dir="rtl">20 Acoustic composition. The instrument 24 may be separate from, or combined with, an echo-impedance sensor 26. Referring again to Fig. 3, if the two instruments are combined together, the sonic velocity measurement configuration shown in Fig. 6 can be provided on a counterbalance vane 130, corresponding to the transducer. Audio 136. Two of the audio instruments 24, 26 may be operated in such a way that interference is avoided, for example, by operating each transformer only when the other is at rest, or by operating</p>

<p dir="rtl">25 The two converters are in non-overlapping frequency bands.</p>

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Figure 6 shows a side projection, while Figure 7 shows a detailed cross section. In the aforementioned projections, it is noted that the far face of the stabilizer blade 130 contains an inset transmitter 142 separated from an array of inset receivers.

146 receivers by acoustic isolation zone 144 acoustic isolation zone. Design is done

<p dir="rtl">5 The acoustic insulation zone 144 is used to attenuate and delay sound wave energy propagating through the body of the instrument from the transmitter 142 to the receivers 146. To this end, the sound insulation zone can include gaps or panels that provide an arrangement of acoustic disparities to reflect and attenuate the sound wave energy. Inserts can be made of a flexible material (for example, vulcanized rubber) that effectively dissipates sound wave energy in the form of heat, thus providing additional attenuation.</p>

<p dir="rtl">10 The careful design of blank shapes results in a set of sound propagation paths that cause harmful interference to receivers over a desired frequency range. By reducing and delaying sound wave energy reaching the receivers through the tool body, the acoustic isolation zone 144 improves the sensitivity of the receivers to acoustic wave energy 152 propagating along the wall of the drill hole 20.</p>

<p dir="rtl">15 The audio transmitters are electrical transducers made of piezoelectric or magnetostrictive material, which allow the instrument 24 to produce programmable audio signals. Alternatively, bending machine rods or other audio transducers may be used. Receivers can be electrical transducers made of piezoelectric material. In some embodiments, the transmitter and receiver adapters are flush with the contacting face surface</p>

<p dir="rtl">20 of the wall 130' to minimize spacing, while in other embodiments the transformers are somewhat housed, covered with a protective coating, and/or placed in a protruding face such that they are maintained at a small spacing from the wall of the drill hole 20 to prevent unnecessary transformer erosion. In some embodiments, the transducers are spaced approximately 1/8 inch, or potentially up to 1/4 inch, and the total space surrounding the transducer does not exceed 10 mart sensing area</p>

<p dir="rtl">25 of the transformer itself. In other embodiments, the distal face of the protrusion is maintained at a distance</p>

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Small spacings (e.g., about 1/10 inch) when rotating the tool into the drill hole. This formation can be achieved by using a set of fasteners on either side of the tool, using an outside diameter somewhat larger than the circle traced by the distal face of the protrusion (pro (Instrument. Some designs result in the transmitter and receiver transducers being placed at an angular level relative to each other.)

<p dir="rtl">5 to each other to increase signal strength.</p>

It is preferable to use at least two receivers 146 to enable the instrument to make deceleration measurements with an accuracy equal to the amount of separation between the receivers. One or more receivers spaced laterally can be added to enable direction of arrival. These measurements allow the tool to correct for the effect of tool rotation.

<p dir="rtl">10 The indicated operating frequencies for the sonic drilling performance recorder are in a range including between 50 kHz and 150 kHz. The operating frequency can be chosen based on the preference between attenuation and wavelength where the wavelength is reduced to a minimum without disturbing the finite attenuation requirement. Disruption of attenuation limits performance, and smaller wavelengths can provide improved spatial resolution of the instrument. When the Microwave Performance Recorder 24 is enabled,</p>

<p dir="rtl">15 The internal control means controls the firing and timing of the sound source 142, and records and processes signals generated by the receivers 146. The internal control means periodically fires the sound source 142, which results in sound pressure waves that propagate within the formation and along the wall of the drill hole 20. As the waves propagate Said pressure following an array of receivers 146, they cause pressure variations that can be detected by the receiver transducers.</p>

<p dir="rtl">20 The internal control device may process the signals to determine latency delays between different P-wave and S-wave receivers according, for example, to the principles and techniques given in</p>

Willis and Toksoz, “Automatic P and S velocity determination from full waveform digital acoustic logs”, Geophysics, v48 n12, December 1983,

p1631-44. Differences in arrival times represent propagation delay, which is combined with information

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Distance to obtain deceleration and/or speed. Because they can be easily derived from each other, the terms "slow" and "speed" are sometimes used interchangeably.

It has been observed that in at least some cases the detected wave images will represent several types of waves, including waves propagating through the tool body (tool waves), waves

<p dir="rtl">5 Compression waves from the formation (P waves), shear waves from the formation (S waves), waves propagating through the drill hole fluid (mud waves), Stoneley waves propagating along the wall of the drill hole. If necessary, the control can process the signals using techniques Processing a form like that was done</p>

In US Patent No. 7,099,810 for separation of B. Mandal species detected by

Different waves and determine their independent rates of deceleration.

<p dir="rtl">10 Receiver array signals can be processed by a downhole control to determine VC (formation-specific compressional wave velocity) and velocities of other acoustic wave modes, and to correlate these measurements with drill hole position and tool orientation to produce one or more images of the drill hole wall's acoustic properties. Store history or image.</p>

Figure 8 shows a functional block diagram of an instrument for recording the performance of micro-acoustic waves and an impedance repeater

<p dir="rtl">15 Built-in echo sounder. A digital signal processor 180 acts as an internal control device for the device by executing a program stored in memory 181. The software configures the processor 180 to collect measurements from several measurement modules such as a position sensor 182 and a resonant impedance sensor 183. (Note that the mentioned modules can be implemented as separate tools in...</p>

<p dir="rtl">20 Downhole assembly, in which case the measurements can be collected by a control/telemetry module 30.)</p>

The software also configures the processor 180 to operate a resonating acoustic impedance sensor 183 and obtain measurements such as surface pressure and velocity, from which an estimate of the acoustic impedance of the formation can be determined. The program also configures the processor 180 to fire source(s) 142 via

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Digital-to-analog converter 184 also configures the processor 180 to acquire wave images received from an array of receivers 146a-146n via analog-to-digital converters 184 186. The digitized wave images can be stored in memory 181 and/or processed to determine particular compressional wave velocities In formation at least. As explained in more detail

<p dir="rtl">5 Below, the processor can combine the velocity of the compressional wave with the acoustic impedance of the formation to determine an estimate of the density of the formation. Alternatively, these measurements can be specified separately and communicated to a module controller or surface treatment facility for integration there. In either case, formation density estimates are linked to the position and orientation of the drilling performance logging tool to provide a density record. A network interface 187 connects the sonic drilling performance recording instrument to a telemetry/control module via a bus</p>

<p dir="rtl">10 Instrument, thus enabling the processor 180 to communicate information to the surface (e.g., velocity measurements, impedance measurements, and/or density records) and receive commands from the surface (e.g., activate the instrument or change its operating parameters).</p>

Figure 9 shows a flowchart of an illustrative method for imaging acoustic impedance/density. The method can be implemented by the program stored in memory and can be implemented by a processor and audio converters, e.g

<p dir="rtl">15 Memory 181, processor 180, and audio transducer 183 are shown in FIG. 8. At frame 192, the echo-impedance performance recording tool 26 is moved along the drill hole and rotated, for example, as part of a drill pipe string or as part of a drill cable tool with a scanning assembly . It is preferable to keep the surface of the surface transducer 305 substantially parallel to the drill hole wall, thereby creating a fluid layer between the drill hole wall and the acoustic transducer.</p>

<p dir="rtl">20 In frame 194, the drilling performance recording tool obtains the tool position and direction (or potentially a time value that can later be assigned to tool position and direction measurements obtained by a separate navigation module). In frame 196, the tool drives the acoustic transducer which causes Use the fluid layer to determine the acoustic impedance measurement at the reverberation frequency of the fluid layer. The acoustic impedance at the peak reverberation frequency can be found by any suitable method, including:</p>

<p dir="rtl">25 Frequency scanning of a narrowband signal, curve-fitting measurements sampled at frequencies</p>

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Performing frequency analysis (e.g., Fourier transform) on a wideband signal response, performing gradient-based search to “find a peak”, adaptive control-based tracking. Once obtained, the re-echo impedance measurement can be set ( By means of a calibration factor) to obtain an estimate of the acoustic impedance of the composition.

<p dir="rtl">5 In frame 196, the tool can also operate a microsound wave performance logging device to obtain a measurement of the sound wave velocity of the formation. Both acoustic impedance and acoustic velocity measurements are related to tool position and orientation measurements obtained from frame 194. Tool position and orientations can be placed in “boxes” to obtain pixels for an image of the drill hole wall (see, for example, Figure 2). The processor integrates the measurements that...</p>

<p dir="rtl">10 It is obtained from each bin by averaging or another statistical technique that exploits the availability of many measurements to improve the signal-to-noise ratio.</p>

In frame 198, the instrument may combine measurements of the measured acoustic impedance and acoustic velocity of the formation to estimate the density of the formation. Frames 192-198 are repeated to produce measurements of the formation's acoustic impedance, the formation's sound wave speed, and/or the formation density, as a function of the position and orientation of the instrument. tt arkm

<p dir="rtl">15 Some or all of these measurements are downhole and optionally communicated to the surface to create image records of these features. Said measurements communicated to the surface may be displayed on a user interface (e.g., display facility 56 of Figure 1) in frame 199.</p>

The functions described in Figure 9 can be distributed throughout the drilling performance recording system or concentrated in a processor

<p dir="rtl">20 Internal drilling performance recording tool. Thus, for example, position measurements, fluid measurements, and formation wave velocity measurements can be taken by separate instruments and communicated to a separate processing facility where the density calculation is performed. Furthermore, functions may be executed in parallel or asynchronously although for explanatory purposes they are described as sequential.</p>

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Figure 10 shows a block diagram of an illustrative surface treatment system suitable for collecting, processing, and displaying drilling performance recording data. In some embodiments, the user may also interact with the system to send a command to the drill hole assembly to adjust its operation in response to the received data. The system shown in Figure 10 can take the form of a computer containing a 50 chassis

<p dir="rtl">5 Display 56 display, and one or more input devices 54 input devicesa or 54b.</p>

Inside the structure there are 50 802 display interfaces, a peripheral interface

804 peripheral interface, 806 bus, 808 processor, 810 memory, 812 information storage device, network interface

814 interface. The 806 bus connects many computer components and transmits their communications.

<p dir="rtl">10 In at least some embodiments, surface telemetry transducers are coupled to the processing system via data acquisition unit 38 and interconnection unit 814 to allow the system to communicate with the downhole assembly. Based on user input received via the terminal interface 804 and program instructions from memory 810 and/or information storage facility 812, the processor processes the telemetry information received via the network interface 814 to generate configuration property registers (which include one</p>

<p dir="rtl">15 (or more pictures of the wall of the drilled hole) and to display them to the user.</p>

The processor 808 and thus the system as a whole generally operates according to one or more programs stored on the information storage medium (e.g., in an information storage medium 812 or a removable information storage medium 52). In the downhole assembly and/or internal control of the acoustic drilling performance recording instrument 26 according to one or more of

<p dir="rtl">20 Programs stored in internal memory. One or more of these programs configures the control method</p>

The tool, the downhole assembly control module, and the surface treatment system independently or in combination implement at least one of the density performance recording methods disclosed herein.

Many modifications, equivalents, and other alternatives will become clear to those skilled in the art once they understand the above disclosure in its entirety. The following protections are intended to be construed as including:

<p dir="rtl">25 All those modifications, equivalents, and substitutions whenever possible.</p>

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Embodiments disclosed herein include:

<p dir="rtl">A: The method involves placing an acoustic transducer at the bottom of the well in a manner largely parallel to the wall of the drill hole, thus creating a fluid layer between the wall and the acoustic transducer, and measuring the acoustic impedance at the surface of the acoustic transducer at the resonant frequency of the fluid layer, and accordingly the acoustic impedance of the formation is determined.</p>

<p dir="rtl">5 B: A system containing an acoustic drilling logging instrument extending the length of a drill hole through a formation, wherein the acoustic drilling logging instrument includes an acoustic transducer positioned substantially parallel to the wall of the drill hole, wherein a fluid layer is created between the wall and the acoustic transducer, and wherein the recording instrument measures Acoustic drilling performance Acoustic impedance of the acoustic transducer at the echo frequency of the fluid bed, and a processor coupled to a acoustic drilling performance recorder that receives acoustic impedance measurements,</p>

<p dir="rtl">10 It determines the audio impedance of the composition based on it.</p>

Each of the embodiments (a) and (b) may include one or more of the following additional elements in any combination:

Element 1: Divide the acoustic impedance by the speed of a formation's sound wave to obtain a measure of the formation's density. Item 2: Repeat the placement, measurement, and division steps mentioned to obtain a density measurement

<p dir="rtl">15 Formation as a function of position along the drill hole, and displaying a measurement of formation density as a function of position along the drill hole. Element 3: Repeat the aforementioned placement, measurement, and division steps to obtain a formation density measurement as a function of position around the drill hole, and display the formation density measurement as a two-dimensional image, where the image represents a function of position along and around the drill hole. Element 4: Sensing the surface pressure of an acoustic transducer and the surface velocity of a transducer, and calculating the acoustic impedance of the acoustic transducer in</p>

<p dir="rtl">20 Image of the ratio of the surface pressure of the acoustic transducer to the surface velocity of the acoustic transducer. Element</p>

<p dir="rtl">5: Determine the echo frequency by determining the maximum amplitude of the acoustic impedance as a function of frequency. Element 6: Determine the resonating frequency of the fluid layer by determining the frequency at which the transducer surface pressure and transducer surface velocity are in phase and/or a frequency of maximum impedance amplitude. Item 7: Conduct a frequency scan to determine the resonating frequency of the fluid layer.</p>

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Acoustic impedance (10*6 kg/m2 s)

Frequency (kHz)

Sensor (art sensor) position

Element 8: Determine the re-echo frequency of the fluid layer by performing a spectral analysis of the audio transducer response to the broadband signal. Element 9: Measure the speed of a formation sound wave using spaced acoustic transducers.

Element 10: A display that presents density as a function of position along the drill hole to the user. Element

<p dir="rtl">5 11: A display device that presents a two-dimensional image of density to the user, where the image is represented as binary</p>

Dimensions are a function of position along and around the drill hole. Element 12: A non-temporary information storage medium in which the processor stores said density as a function of position along the drill hole. Item 13: Where the acoustic transducer is a piezoelectric transducer. Item 14: Wherein the audio transformer includes a speaker coil, a plate placed on the outside of the transformer, and a strain sensor placed between the coil

<p dir="rtl">10 Speaker and tablet. Item 15: Wherein the transducer is part of a drill collar. Item 16: The echo frequency ranges from 10 kHz to 250 kHz. Element 17: The acoustic drilling performance recording tool produces a broadband signal and the processor determines the echo frequency of the fluid layer by performing a spectral analysis of the acoustic transducer response to the broadband signal. Element 18: Where audio signals are issued and received in a drilling cable environment.</p>

<p dir="rtl">15 Element 19: Also includes a progressive array transducer that reduces the effects of footnote.</p>

Bookmark the drawings

Figure 5:

a -

20 B -

Figure 8:

182 -

183 - Ring sensor

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<p dir="rtl">142 - Source(s)</p>

146A - Receiver 1

<p dir="rtl">146N - N receiver</p>

<p dir="rtl">180 - Digital signal processor</p>

5 181 - Memory

<p dir="rtl">187 - Interface network</p>

Figure 9:

<p dir="rtl">192 - Move and rotate the tool along the drill hole</p>

<p dir="rtl">194 - Measure position and direction</p>

<p dir="rtl">10 196 - Measuring velocity and echo impedance</p>

<p dir="rtl">198 - Find the density of the composition</p>

<p dir="rtl">199 - Accumulating data and displaying an impedance or density image record</p>

A - The beginning

Figure 10:

15 56 - Display device

802 - Interface display

808 - Processor

810 - Memory

804 - Terminal interface

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814 - Modem or network interface

812 - A means of storing information

54B - Indicator method

54A - Keyboard

5 38 - Data acquisition unit(s).

52 - Removable storage media

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