WO2010132070A1 - Mesures de la vitesse acoustique à l'aide de transducteurs inclinés - Google Patents

Mesures de la vitesse acoustique à l'aide de transducteurs inclinés Download PDF

Info

Publication number
WO2010132070A1
WO2010132070A1 PCT/US2009/050859 US2009050859W WO2010132070A1 WO 2010132070 A1 WO2010132070 A1 WO 2010132070A1 US 2009050859 W US2009050859 W US 2009050859W WO 2010132070 A1 WO2010132070 A1 WO 2010132070A1
Authority
WO
WIPO (PCT)
Prior art keywords
acoustic
transducer
pulse
drilling fluid
downhole tool
Prior art date
Application number
PCT/US2009/050859
Other languages
English (en)
Inventor
Paul Cooper
Kristopher V. Sherrill
Ricardo Ortiz
Daniel Flores
Batakrishna Bandal
Original Assignee
Halliburton Energy Services, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to US13/264,336 priority Critical patent/US9631480B2/en
Publication of WO2010132070A1 publication Critical patent/WO2010132070A1/fr

Links

Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/44—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/08—Measuring diameters or related dimensions at the borehole
    • E21B47/085—Measuring diameters or related dimensions at the borehole using radiant means, e.g. acoustic, radioactive or electromagnetic

Definitions

  • the application relates generally to downhole drilling.
  • the application relates to measuring a velocity of a drilling fluid used during the downhole drilling.
  • an accurate determination of a shape of a borehole is important.
  • a number of other downhole measurements are sensitive to a stand-off of the downhole tools from the formation.
  • Knowledge of the borehole shape may be required to apply corrections to these downhole measurements.
  • a determination of the shape of the borehole has various other applications. For example, for completing a well, an accurate knowledge of the borehole shape is important in hole- volume calculations for cementing.
  • Figure 1 illustrates a downhole tool having transducers, according to example embodiments.
  • Figure 2 illustrates a downhole tool having transducers, according to other example embodiments.
  • Figure 3 illustrates a downhole tool having transducers, according to other example embodiments.
  • Figure 4A illustrates a drilling well during Measurement While
  • Figure 4B illustrates a drilling well during wireline logging operations, according to some embodiments.
  • Figure 5 illustrates a portion of a downhole tool having at least one transducer, according to example embodiments.
  • Figure 6 illustrates a portion of a downhole tool having at least one transducer, according to example embodiments.
  • Figure 7 illustrates a portion of a downhole tool having at least one transducer, according to example embodiments.
  • Figure 8 illustrates a portion of a downhole tool having at least one transducer, according to example embodiments.
  • Figure 9 illustrates a portion of a downhole tool having at least one transducer, according to example embodiments.
  • Figure 10 illustrates a portion of a downhole tool having at least one transducer, according to example embodiments.
  • Figure 11 illustrates a portion of a downhole tool having at least one transducer, according to example embodiments.
  • Figure 12 illustrates a portion of a downhole tool having at least one transducer, according to example embodiments.
  • a downhole tool comprises tilted (angled) and non-tilted transducers relative to the outer surface of the downhole tool. These transducers may be acoustic transducers that are used to measure a velocity of sound (e.g., ultrasound) propagation in the drilling fluid in a downhole environment.
  • a downhole tool comprises a non-tilted transducer that operates in a pulse-echo mode to receive an echo of a pulse that is reflected off the formation wall or well bore.
  • the downhole tool may comprise a tilted transducer that operates in a pitch-catch mode with a different transducer.
  • the tilted transducer may operate in a pitch-catch mode with the non- tilted transducer that is also operating in the pulse-echo mode.
  • the tilted transducer may operate in a pitch-catch mode with a different non- tilted transducer. While described such that the transducers are positioned in a downhole tool, some embodiments are not so limited.
  • the transducers may be positioned at different locations along the drill string or wireline tool. For example, in some embodiments, one or more of the transducers maybe positioned within the drill bit of the drill string. [0019] In some embodiments, a single dual-element transducer may be used to measure the velocity of sound propagation in the drilling fluid.
  • the dual-element transducer may comprise a first transducer element that is non-tilted relative to the outer surface of the downhole tool.
  • the dual-element transducer may also comprise a second transducer element that is tilted relative to the outer surface of the downhole tool.
  • tilted and non-tilted transducers provides measurements of sound paths that are two different lengths. The difference in arrival times of the two sound pulses can be used to determine an in-situ velocity of sound downhole. The velocity measurement may be used to calculate various downhole parameters (e.g., borehole diameters).
  • Figure 1 illustrates a downhole tool having transducers, according to example embodiments.
  • Figure 1 illustrates a downhole tool 104 that may be part of a drill string for drilling into a formation 102. As shown, the downhole tool 104 is within a borehole that is drilled into the formation 102. An example MWD operating environment wherein the downhole tool 104 may operate is described in more detail below.
  • the formation 102 comprises a face 120.
  • An annulus 105 is between the downhole tool 104 and the formation 102. From the Earth's surface to downhole, a drilling fluid may pass through a drill string (including the downhole tool 104) and out an end of a drill bit positioned at the end of the drill string.
  • the drilling fluid may then return to the Earth's surface through the annulus 105.
  • a standoff (from the downhole tool 104 to the formation 102) is a distance d.
  • a number of downhole measurements are sensitive to the standoff. For example, a measurement of a resistivity of the formation may be corrected to account for the standoff.
  • determining the standoff along different points at different depths of the borehole also allows for a determination of a shape of the borehole. For well completion, a knowledge of the shape of the borehole is important in the calculation of the in hole- volume calculations for cementing.
  • the downhole tool 104 comprises a transducer 106 and a transducer
  • the transducer 106 and the transducer 108 may emit and detect acoustic waves.
  • the transducer 106 and the transducer 108 may emit and detect ultrasonic waves.
  • the transducer 106 and the transducer 108 may be only an emitter or a detector. In particular, if the transducer only provides for emission of acoustic waves, the transducer may be only an emitter.
  • the transducer 106 and the transducer 108 include a face 107 and a face 109, respectively.
  • the face 107 of the transducer 106 is generally parallel to the face 120 of the formation 102. While the face 107 of the transducer 106 is at the outer diameter of the downhole tool 104, embodiments are not so limited. For example, in some embodiments, the transducer 106 may be embedded in the downhole tool 104 a given depth. The face of transducer may be covered by different material for protection of the face 107, while allowing for the emission of the acoustic waves without interference.
  • the face 109 of the transducer 108 is not parallel with the face 120 of the formation 102.
  • the transducer 108 is tilted at some angle, ⁇ , relative to the surface of the downhole tool 104 and the face 120 of the formation 102.
  • the angle may be in a range of 1 to 89 degrees.
  • the angle may be approximately 5 degrees, 10 degrees, 15 degrees, 20 degrees, 25 degrees, 30 degrees, 35 degrees, 40 degrees, 45 degrees, 50 degrees, 55 degrees, 60 degrees, 65 degrees, 70 degrees, 75 degrees, 80 degrees, 85 degrees, etc.
  • an opening 125 is cut into the downhole tool 104.
  • the opening 125 is filled with different material to protect the face 109 while allowing for the emission of the acoustic waves without interference.
  • the distance between the transducer 106 and the transducer 108 is L.
  • the transducer 106 and the transducer 108 may comprise a piezoelectric ceramic or a magnetostrictive material that converts electric energy into vibration and vice versa.
  • the transducer 106 may operate both as a transmitter and a receiver. In operation, in some embodiments, the transducer 106 operates in a pulse- echo mode.
  • the transducer 106 is configured to emit a pulse (e.g., in a collimated fashion) in a direction substantially toward the surface 120 of the formation 102.
  • the transducer 106 then receives the reflection of the vibration off the surface 120 (the echo).
  • the transducer 106 may determine the travel time (I A ) of the reflected pulse.
  • the transducer 108 operates in a pitch-catch mode.
  • the transducer 108 is configured to emit a pulse towards the face 120 of the formation 102 at an angle, ⁇ (the pitch).
  • the pulse is then reflected, according to SnelPs law.
  • the reflection is received by the transducer 106 (the catch).
  • the travel time (t ⁇ ) of the reflected pulse may be determined.
  • the difference in the two travel times, ⁇ A and t ⁇ is due to a difference in the path length in the drilling fluid for the two pulses. Therefore, these two measurements may be used to calculate an acoustic velocity (v) in the drilling fluid.
  • v acoustic velocity
  • t B _ 2((L/2) 2 + j2 ⁇ l/2 /
  • Electronics may determine the velocity (v). Such electronics may be downhole, at the surface (local or remote to the drilling site) or a combination thereof.
  • FIG. 2 illustrates a downhole tool having transducers, according to other example embodiments, hi this configuration, the downhole tool comprises two transducers separated by different longitudinal distances from the main "pulse-echo" transducer.
  • Figure 2 illustrates a downhole tool 204 that may be part of a drill string for drilling into a formation 202.
  • the downhole tool 204 is within a borehole that is drilled into the formation 202.
  • An example MWD operating environment wherein the downhole tool 204 may operate is described in more detail below.
  • the formation 202 comprises a face 220.
  • An annulus 205 is between the downhole tool 204 and the formation 202. From the Earth's surface to downhole, a drilling fluid may pass through a drill string (including the downhole tool 204) and out an end of a drill bit positioned at the end of the drill string. The drilling fluid may then return to the Earth's surface through the annulus 205.
  • a standoff (from the downhole tool 204 to the formation 202) is a distance d.
  • the downhole tool 204 comprises a transducer 206, a transducer 208 and a transducer 211.
  • the transducer 206, the transducer 208 and the transducer 211 may emit and detect acoustic waves.
  • the transducer 206, the transducer 208 and the transducer 211 may emit and detect ultrasonic waves.
  • the transducer 206, the transducer 208 and the transducer 211 may be only an emitter or a detector, hi particular, if the transducer only provides for emission of acoustic waves, the transducer may be only an emitter.
  • the transducer 206, the transducer 208 and the transducer 211 include a face 207, a face 209 and a face 225, respectively.
  • the face 207 of the transducer 206 is generally parallel to the face 220 of the formation 202. While the face 207 of the transducer 206 is at the outer diameter of the downhole tool 204, embodiments are not so limited. For example, in some embodiments, the transducer 206 may be embedded in the downhole tool 204 a given depth. The face of transducer may be covered by different material for protection of the face 207, while allowing for the emission of the acoustic waves without interference.
  • the face 209 and the face 225 are not parallel with the face 220 of the formation 202.
  • the transducer 208 and the transducer 211 are tilted at some angle, ⁇ , relative to the surface of the downhole tool 204 and the face 220 of the formation 202.
  • the distance from the transducer 211 to the transducer 206 and the distance from the transducer 225 to the transducer 206 are the same, hi some embodiments, such distances are different.
  • the angle, ⁇ , for the transducer 211 and the transducer 225 may be the same or different, hi some embodiments, the angles may be in a range of 1 to 89 degrees.
  • the angles may be approximately 5 degrees, 10 degrees, 15 degrees, 20 degrees, 25 degrees, 30 degrees, 35 degrees, 40 degrees, 45 degrees, 50 degrees, 55 degrees, 60 degrees, 65 degrees, 70 degrees, 75 degrees, 80 degrees, 85 degrees, etc.
  • an opening 125 is cut into the downhole tool 104.
  • the opening 125 is filled with different material to protect the faces 209 and 225 while allowing for the emission of the acoustic waves without interference.
  • the transducer 206, the transducer 208 and the transducer 211 may comprise a piezoelectric ceramic or a magnetostrictive material that converts electric energy into vibration and vice versa.
  • the transducer 206 may operate both as a transmitter and a receiver, hi operation, in some embodiments, the transducer 206 operates in a pulse-echo mode.
  • the transducer 206 is configured to emit a pulse (e.g., in a collimated fashion) in a direction substantially toward the surface 220 of the formation 202.
  • the transducer 206 then receives the reflection of the vibration off the surface 220 (the echo).
  • the transducer 206 may determine the travel time (t ⁇ ) of the reflected pulse.
  • the transducer 208 and the transducer 211 operate in a pitch-catch mode.
  • the transducer 208 and the transducer 211 are configured to emit a pulse towards the face 220 of the formation 202 at an angle, ⁇ (the pitch).
  • the pulse is then reflected, according to Snell's law.
  • the reflections are received by the transducer 206 (the catch).
  • the travel time (t ⁇ ) and the travel time (tc) for the pulse from the transducer 208 and the transducer 211, respectively, of the reflected pulses may be determined.
  • the pairs of measurements O A , t ⁇ ) and (t A , tc) may be used to calculate two values for the acoustic velocity.
  • Figure 3 illustrates a downhole tool having transducers, according to other example embodiments.
  • Figure 3 illustrates a downhole tool 304 that may be part of a drill string for drilling into a formation 302. As shown, the downhole tool 304 is within a borehole that is drilled into the formation 302. An example MWD operating environment wherein the downhole tool 304 may operate is described in more detail below.
  • the formation 302 comprises a face 303.
  • An annulus 350 is between the downhole tool 304 and the formation 302.
  • a drilling fluid may pass through a drill string (including the downhole tool 304) and out an end of a drill bit positioned at the end of the drill string. The drilling fluid may then return to the Earth's surface through the annulus 350.
  • a standoff (from the downhole tool 304 to the formation 302) is a distance d.
  • Figure 3 comprises a dual-element acoustic transducer. Accordingly, two acoustic transducers are in a same casing, thereby reducing its footprint. The operations are similar to those described for the configuration of Figure 1.
  • the downhole tool 304 comprises a dual-element transducer 306.
  • the dual-element transducer 306 includes a casing 310.
  • the casing 310 encloses a first acoustic element 316 and a second acoustic element 318.
  • the dual-element transducer 306 also includes a backing material 314 for both element 316 and 318.
  • An acoustic matching material 322 is positioned in front of the second acoustic element 318 (relative to the face of the dual-element transducer 306).
  • a wear plate 312 is positioned in front of both first acoustic transducer element 316 and the second acoustic transducer element 318.
  • the first acoustic transducer element 316 and the second acoustic transducer element 318 may emit and detect acoustic waves.
  • the transducer element 316 and the transducer element 318 may emit and detect ultrasonic waves.
  • the transducer element 316 and the transducer element 318 may be only an emitter or a detector. In particular, if the transducer only provides for emission of acoustic waves, the transducer may be only an emitter.
  • the transducer element 316 and the transducer element 318 include a face 370 and a face 372, respectively.
  • the face 370 of the transducer element 316 is essentially parallel to the face 303 of the formation 302. While the face 370 of the transducer element 316 is at the outer diameter of the downhole tool 304, embodiments are not so limited. For example, in some embodiments, the transducer element 316 may be embedded in the downhole tool 304 a given depth.
  • the transducer element 318 is tilted at some angle, ⁇ , relative to the surface of the downhole tool 304 and the face 303 of the formation 302.
  • the angle may be in a range of 1 to 89 degrees.
  • the angle may be_approximately 5 degrees, 10 degrees, 15 degrees, 20 degrees, 25 degrees, 30 degrees, 35 degrees, 40 degrees, 45 degrees, 50 degrees, 55 degrees, 60 degrees, 65 degrees, 70 degrees, 75 degrees, 80 degrees, 85 degrees, etc.
  • the distance between the transducer element 316 and the transducer element 318 is L.
  • the transducer element 316 and the transducer element 318 may comprise a piezoelectric ceramic or a magnetostrictive material that converts electric energy into vibration and vice versa.
  • the transducer element 316 may operate both as a transmitter and a receiver. In operation, in some embodiments, the transducer element 316 operates in a pulse-echo mode.
  • the transducer element 316 is configured to emit a pulse (e.g., in a collimated fashion) in a direction substantially toward the surface 303 of the formation 302.
  • the transducer element 316 then receives the reflection of the vibration off the surface 302 (the echo).
  • the transducer element 316 may determine the travel time (t A ) of the reflected pulse.
  • the transducer element 318 operates in a pitch-catch mode.
  • the transducer element 318 is configured to emit a pulse towards the face 303 of the formation 302 at an angle, ⁇ (the pitch).
  • the pulse is then reflected, according to Snell's law.
  • the reflection is received by the transducer element 316 (the catch).
  • the travel time (t ⁇ ) of the reflected pulse may be determined.
  • the difference in the two travel times, t A and t ⁇ is due to a difference in the path length in the drilling fluid for the two pulses. Therefore, these two measurements may be used to calculate an acoustic velocity (v) in the drilling fluid, hi particular,
  • Electronics may determine the velocity (v). Such electronics may be downhole, at the surface (local or remote to the drilling site) or a combination thereof. [0059] In some embodiments, to remove the impact of a bad measurement, a
  • the moving-average speed of sound will be maintained, based on a fixed number of previous good measurements.
  • the current speed of sound measurement will be compared to this average. If the current speed and the average differ by a given amount, the current speed is discarded. In some embodiments, if the current speed does not differ by the given amount, the current speed is considered a good measurement and is used to update the moving average.
  • the current moving average speed of sound may be used to convert the travel time measured by the transducer 106 in the "pulse-echo" mode into a stand-off to the borehole wall. This measurement of the stand-off may be used by other instruments or tools in the drill string.
  • Figures 5 - 12 illustrate an example of devices that can be used in a method of measurement, which can be used alone or in combination with other embodiments herein.
  • the measurement can be more accurately made by cleaning formation cuttings from the location where the measurement is taken.
  • a measurement can be taken in a cavity 510 using one or more transducers 512, where the cavity 510 is recessed within a portion of the downhole tool or wire.
  • the cavity 510 includes an opening 516 to the drilling fluid, and the cavity 510 is recessed from an outer surface 514 of the tool or wireline.
  • a cavity cleaning piston 520 is movably disposed within the cavity 510, and moves along a piston axis.
  • the piston 520 has multiple positions within the cavity 510
  • the piston 520 optionally has a similar cross-section as the cross-section of the cavity.
  • the formation cuttings are cleaned from the cavity in several different manners.
  • the piston 520 remains in a default position recessed away from the opening 516 ( Figure 5), which allows for cuttings 518 to be packed within the cavity 510 during the downhole processing, such as drilling.
  • the cavity 510 can be cleaned by moving the piston 520 toward the outer surface 514 of the tool such that the cuttings packed within the cavity 510 are displaced out of the cavity 510, as shown in Figure 6.
  • the piston 520 retracts away from the outer surface 514 and back within the cavity 510, as shown in Figure 7. Since the piston 520 is retracted, drilling fluid fills the cavity 510.
  • the transducer 512 sends a signal and measures time of flight across the cavity 510.
  • the information from the transducer 512 can be used to determine the drilling fluid velocity, for instance with a processor, as discussed above.
  • the transducer 512 may operate both as a transmitter and a receiver.
  • the transducer 512 is configured to emit a pulse, in an example, in a direction substantially toward an opposite surface of the cavity 510.
  • the transducer 512 then receives the reflection of the vibration off the surface (the echo), which is used to determine the travel time of the reflected pulse.
  • the piston 520 has a default position that is substantially flush with the outer surface 514 of the tool, preventing any cuttings from filling the cavity 510.
  • the piston 520 is retracted within the cavity, and drilling fluid fills the cavity 510.
  • a measurement of the fluid is then taken.
  • the transducer 512 emits a pulse as described above, in an example, in a direction substantially toward an opposite surface of the cavity 510.
  • a portion of the cavity acts as a reflector and reflects the pulse.
  • the transducer 512 then receives the reflection of the vibration off the surface (the echo), and the information is used to determine the travel time of the reflected pulse.
  • FIGs 10 - 12 illustrate another example of the method of measurement.
  • the downhole tool includes a cavity 510 therein, and the cavity 510 has an opening 516 allowing access to the cavity 510.
  • a grate 530 Disposed on or in the opening 516 is a grate 530, which operates as a filter.
  • the piston 520 can have multiple positions and in an option is disposed over the opening 516, or otherwise closes the opening 516 in a closed position.
  • the piston 520 is retracted within the cavity and away from the opening 516, as shown in Figure 11, and draws drilling fluid within the cavity 510.
  • the piston 520 moves along a piston axis which is substantially parallel with the outer surface 514 of the tool.
  • the drilling fluid is then measured, for example, the acoustic velocity is measured.
  • the transducer 512 emits a pulse as described above, and receives the reflection of the vibration off a surface (the echo), which is used to determine the travel time of the reflected pulse.
  • the surface of the piston acts as the reflector for the acoustic energy from the transducer 512.
  • a transducer is also on the piston 520, resulting in a transmitter and receiver arrangement.
  • the piston 520 can have multiple positions and in an option is disposed in two or more positions, such as at least a first position and a second position, hi an example, the piston 520 is disposed in positions di and d 2 , as shown in Figures 11 and 12, where the distance d is measured from a face of the piston to the transducer 512.
  • the travel time of the acoustic energy can be measured as follows:
  • the embodiments can be used to detect downhole gas. For instance, when gas bubbles are entering the mud downhole, the acoustic velocity of the mud will decrease, hi detecting a decrease in the acoustic velocity of the mud, this can be used as an early warning that gas may be in the system. In measuring the velocity of the mud downhole, the information regarding the decrease in velocity, or potential presence of gas, can be obtained earlier than when the measurements are taken from the surface.
  • Figure 4A illustrates a drilling well during Measurement While Drilling
  • a system 464 may also form a portion of a drilling rig 402 located at a surface 404 of a well 406.
  • the drilling rig 402 may provide support for a drill string 408.
  • the drill string 408 may operate to penetrate a rotary table 410 for drilling a borehole 412 through subsurface formations 414.
  • the drill string 408 may include a Kelly 416, drill pipe 418, and a bottom hole assembly 420, perhaps located at the lower portion of the drill pipe 418.
  • the bottom hole assembly 420 may include drill collars 422, a downhole tool 424, and a drill bit 426.
  • the drill bit 426 may operate to create a borehole 412 by penetrating the surface 404 and subsurface formations 414.
  • the downhole tool 424 may comprise any of a number of different types of tools including MWD (measurement while drilling) tools, LWD (logging while drilling) tools, and others.
  • Kelly 416, the drill pipe 418, and the bottom hole assembly 420 may be rotated by the rotary table 410.
  • the bottom hole assembly 420 may also be rotated by a motor (e.g., a mud motor) that is located downhole.
  • the drill collars 422 may be used to add weight to the drill bit 426.
  • the drill collars 422 also may stiffen the bottom hole assembly 420 to allow the bottom hole assembly 420 to transfer the added weight to the drill bit 426, and in turn, assist the drill bit 426 in penetrating the surface 404 and subsurface formations 414.
  • a mud pump 432 may pump drilling fluid
  • drilling mud (sometimes known by those of skill in the art as "drilling mud") from a mud pit 434 through a hose 436 into the drill pipe 418 and down to the drill bit 426.
  • the drilling fluid can flow out from the drill bit 426 and be returned to the surface 404 through an annular area 440 between the drill pipe 418 and the sides of the borehole 412.
  • the drilling fluid may then be returned to the mud pit 434, where such fluid is filtered.
  • the drilling fluid can be used to cool the drill bit 426, as well as to provide lubrication for the drill bit 426 during drilling operations. Additionally, the drilling fluid may be used to remove subsurface formation 414 cuttings created by operating the drill bit 426.
  • FIG. 4B illustrates a drilling well during wireline logging operations, according to some embodiments.
  • a drilling platform 486 is equipped with a derrick 488 that supports a hoist 490.
  • Drilling of oil and gas wells is commonly carried out by a string of drill pipes connected together so as to form a drilling string that is lowered through a rotary table 410 into a wellbore or borehole 412.
  • the drilling string has been temporarily removed from the borehole 412 to allow a wireline logging tool body 470, such as a probe or sonde, to be lowered by wireline or logging cable 474 into the borehole 412.
  • the tool body 470 is lowered to the bottom of the region of interest and subsequently pulled upward at a substantially constant speed.
  • instruments included in the tool body 470 may be used to perform measurements on the subsurface formations 414 adjacent the borehole 412 as they pass by.
  • the measurement data can be communicated to a logging facility 492 for storage, processing, and analysis.
  • the logging facility 492 may be provided with electronic equipment for various types of signal processing. Similar log data may be gathered and analyzed during drilling operations (e.g., during Logging While Drilling, or LWD operations).
  • numerous specific details such as logic implementations, opcodes, means to specify operands, resource partitioning/sharing/duplication implementations, types and interrelationships of system components, and logic partitioning/integration choices are set forth in order to provide a more thorough understanding of the present invention.

Landscapes

  • Physics & Mathematics (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Geophysics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Mining & Mineral Resources (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Acoustics & Sound (AREA)
  • General Physics & Mathematics (AREA)
  • Electromagnetism (AREA)
  • Fluid Mechanics (AREA)
  • Remote Sensing (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Geophysics And Detection Of Objects (AREA)

Abstract

La présente invention concerne un procédé qui consiste à émettre une première impulsion acoustique dans un fluide de forage dans un trou de forage, à l'aide d'un premier transducteur acoustique dans un outil de fond de trou, une face du premier transducteur acoustique formant un angle qui n'est pas parallèle à une surface externe de l'outil de fond de trou. Le procédé consiste à détecter la première impulsion acoustique après que cette dernière s'est déplacée à travers le fluide de forage et s'est réfléchie sur une paroi du trou de forage, à l'aide d'un second transducteur acoustique dans l'outil de fond de trou, une face du second transducteur acoustique étant approximativement parallèle à la surface externe de l'outil de fond de trou. Le procédé consiste également à émettre une seconde impulsion acoustique dans le fluide de forage dans le trou de forage, à détecter la seconde impulsion acoustique après qu'elle s'est déplacée à travers le fluide de forage et s'est réfléchie par la paroi du trou de forage, à l'aide du second transducteur acoustique.
PCT/US2009/050859 2009-05-11 2009-07-16 Mesures de la vitesse acoustique à l'aide de transducteurs inclinés WO2010132070A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
US13/264,336 US9631480B2 (en) 2009-05-11 2009-07-16 Acoustic velocity measurements using tilted transducers

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
PCT/US2009/002905 WO2010132039A1 (fr) 2009-05-11 2009-05-11 Mesures de vitesse acoustique en utilisant des transducteurs inclinés
USPCT/US2009/002905 2009-05-11

Publications (1)

Publication Number Publication Date
WO2010132070A1 true WO2010132070A1 (fr) 2010-11-18

Family

ID=41531564

Family Applications (2)

Application Number Title Priority Date Filing Date
PCT/US2009/002905 WO2010132039A1 (fr) 2009-05-11 2009-05-11 Mesures de vitesse acoustique en utilisant des transducteurs inclinés
PCT/US2009/050859 WO2010132070A1 (fr) 2009-05-11 2009-07-16 Mesures de la vitesse acoustique à l'aide de transducteurs inclinés

Family Applications Before (1)

Application Number Title Priority Date Filing Date
PCT/US2009/002905 WO2010132039A1 (fr) 2009-05-11 2009-05-11 Mesures de vitesse acoustique en utilisant des transducteurs inclinés

Country Status (1)

Country Link
WO (2) WO2010132039A1 (fr)

Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP2764382A4 (fr) * 2011-10-03 2016-04-06 Services Petroliers Schlumberger Applications basées sur des propriétés de fluides mesurées en fond de trou
US9631480B2 (en) 2009-05-11 2017-04-25 Halliburton Energy Services, Inc. Acoustic velocity measurements using tilted transducers

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2016204775A1 (fr) * 2015-06-19 2016-12-22 Halliburton Energy Services, Inc. Systèmes et procédés employant un outil de compas acoustique avec correction d'inclinaison d'outil

Citations (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3363719A (en) * 1965-12-23 1968-01-16 Dresser Ind Acoustic velocity logging method and apparatus having lateral and longitudinal receiovers
US3542150A (en) * 1968-10-10 1970-11-24 Dresser Ind Acoustic well-logging apparatus having angled acoustic transducers
US3648513A (en) * 1970-01-05 1972-03-14 Dow Chemical Co Sonic method and means for determination of solution concentrations
US3937060A (en) * 1974-02-06 1976-02-10 Hydril Company Mud gas content sampling device
US4208906A (en) * 1978-05-08 1980-06-24 Interstate Electronics Corp. Mud gas ratio and mud flow velocity sensor
US4601024A (en) * 1981-03-10 1986-07-15 Amoco Corporation Borehole televiewer system using multiple transducer subsystems
US5533402A (en) * 1994-05-11 1996-07-09 Artann Corporation Method and apparatus for measuring acoustic parameters in liquids using cylindrical ultrasonic standing waves
US6125079A (en) * 1997-05-14 2000-09-26 Gas Research Institute System and method for providing dual distance transducers to image behind an acoustically reflective layer
US6305233B1 (en) * 1995-10-19 2001-10-23 Commonwealth Scientific And Industrial Research Organisation Digital speed determination in ultrasonic flow measurements
WO2005100978A1 (fr) * 2004-04-09 2005-10-27 Shell Internationale Research Maatschappij B.V. Appareil et procedes destines a determiner, par voie acoustique, des proprietes fluidiques pendant un echantillonnage
US20070022803A1 (en) * 2005-08-01 2007-02-01 Baker Hughes, Inc. Acoustic fluid analyzer

Family Cites Families (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
DE3503488A1 (de) * 1985-01-30 1986-07-31 Prakla-Seismos Gmbh, 3000 Hannover Verfahren und einrichtung zur echometrischen ausmessung einer unterirdischen kaverne
US5763773A (en) * 1996-09-20 1998-06-09 Halliburton Energy Services, Inc. Rotating multi-parameter bond tool
US6021093A (en) * 1997-05-14 2000-02-01 Gas Research Institute Transducer configuration having a multiple viewing position feature
US6310426B1 (en) * 1999-07-14 2001-10-30 Halliburton Energy Services, Inc. High resolution focused ultrasonic transducer, for LWD method of making and using same
US6678616B1 (en) * 1999-11-05 2004-01-13 Schlumberger Technology Corporation Method and tool for producing a formation velocity image data set
US20040095847A1 (en) * 2002-11-18 2004-05-20 Baker Hughes Incorporated Acoustic devices to measure ultrasound velocity in drilling mud
EP1441105B1 (fr) * 2002-12-31 2006-03-08 Services Petroliers Schlumberger Méthode et dispositif pour mesurer la vitesse d'ultrasons dans les fluides de forage
US7587936B2 (en) * 2007-02-01 2009-09-15 Smith International Inc. Apparatus and method for determining drilling fluid acoustic properties

Patent Citations (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3363719A (en) * 1965-12-23 1968-01-16 Dresser Ind Acoustic velocity logging method and apparatus having lateral and longitudinal receiovers
US3542150A (en) * 1968-10-10 1970-11-24 Dresser Ind Acoustic well-logging apparatus having angled acoustic transducers
US3648513A (en) * 1970-01-05 1972-03-14 Dow Chemical Co Sonic method and means for determination of solution concentrations
US3937060A (en) * 1974-02-06 1976-02-10 Hydril Company Mud gas content sampling device
US4208906A (en) * 1978-05-08 1980-06-24 Interstate Electronics Corp. Mud gas ratio and mud flow velocity sensor
US4601024A (en) * 1981-03-10 1986-07-15 Amoco Corporation Borehole televiewer system using multiple transducer subsystems
US5533402A (en) * 1994-05-11 1996-07-09 Artann Corporation Method and apparatus for measuring acoustic parameters in liquids using cylindrical ultrasonic standing waves
US6305233B1 (en) * 1995-10-19 2001-10-23 Commonwealth Scientific And Industrial Research Organisation Digital speed determination in ultrasonic flow measurements
US6125079A (en) * 1997-05-14 2000-09-26 Gas Research Institute System and method for providing dual distance transducers to image behind an acoustically reflective layer
WO2005100978A1 (fr) * 2004-04-09 2005-10-27 Shell Internationale Research Maatschappij B.V. Appareil et procedes destines a determiner, par voie acoustique, des proprietes fluidiques pendant un echantillonnage
US20070022803A1 (en) * 2005-08-01 2007-02-01 Baker Hughes, Inc. Acoustic fluid analyzer

Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9631480B2 (en) 2009-05-11 2017-04-25 Halliburton Energy Services, Inc. Acoustic velocity measurements using tilted transducers
EP2764382A4 (fr) * 2011-10-03 2016-04-06 Services Petroliers Schlumberger Applications basées sur des propriétés de fluides mesurées en fond de trou

Also Published As

Publication number Publication date
WO2010132039A1 (fr) 2010-11-18

Similar Documents

Publication Publication Date Title
US9631480B2 (en) Acoustic velocity measurements using tilted transducers
US9891335B2 (en) Wireless logging of fluid filled boreholes
US7418865B2 (en) Method and apparatus for ultrasound velocity measurements in drilling fluids
EP0646697B1 (fr) Dispositif et méthode pour mesurer les dimensions dans un trou de sorage
US20040095847A1 (en) Acoustic devices to measure ultrasound velocity in drilling mud
US20050259512A1 (en) Acoustic caliper with transducer array for improved off-center performance
EP3172399B1 (fr) Capteur uniquement à réflexion en de multiples angles pour une détermination quasi en temps réel de propriétés acoustiques d'un fluide en fond de trou
CA2931182C (fr) Determination de longueur de materiel tubulaire de puits de forage par mesures d'echo d'impulsion
US20160018548A1 (en) Methods and apparatus for wellbore evaluation
US20220325622A1 (en) Self-calibrated method of determining borehole fluid acoustic properties
EP3097263B1 (fr) Capteur exclusivement à réflexion pour détecter l'impédance acoustique, la vitesse du son et la densité d'un fluide
US10408052B2 (en) Measuring frequency-dependent acoustic attenuation
WO2012039707A1 (fr) Systèmes et procédés d'imagerie de densité par micro-sons réalisée en même temps que le forage
WO2010132070A1 (fr) Mesures de la vitesse acoustique à l'aide de transducteurs inclinés
US10921478B2 (en) Method and transducer for acoustic logging
WO2002068796A1 (fr) Determination de la forme d"un trou de forage
WO2012068205A2 (fr) Procédé et appareil servant à déterminer la taille d'un trou de forage
Aithoff et al. MWD ultrasonic caliper advanced detection techniques

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 09844743

Country of ref document: EP

Kind code of ref document: A1

NENP Non-entry into the national phase

Ref country code: DE

WWE Wipo information: entry into national phase

Ref document number: 13264336

Country of ref document: US

122 Ep: pct application non-entry in european phase

Ref document number: 09844743

Country of ref document: EP

Kind code of ref document: A1