WO2010132039A1 - Mesures de vitesse acoustique en utilisant des transducteurs inclinés - Google Patents

Mesures de vitesse acoustique en utilisant des transducteurs inclinés Download PDF

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Publication number
WO2010132039A1
WO2010132039A1 PCT/US2009/002905 US2009002905W WO2010132039A1 WO 2010132039 A1 WO2010132039 A1 WO 2010132039A1 US 2009002905 W US2009002905 W US 2009002905W WO 2010132039 A1 WO2010132039 A1 WO 2010132039A1
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WO
WIPO (PCT)
Prior art keywords
acoustic
transducer
pulse
drilling fluid
downhole tool
Prior art date
Application number
PCT/US2009/002905
Other languages
English (en)
Inventor
Paul Cooper
Batakrishna Mandal
Original Assignee
Paul Cooper
Batakrishna Mandal
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 Paul Cooper, Batakrishna Mandal filed Critical Paul Cooper
Priority to PCT/US2009/002905 priority Critical patent/WO2010132039A1/fr
Priority to US13/264,336 priority patent/US9631480B2/en
Priority to PCT/US2009/050859 priority patent/WO2010132070A1/fr
Publication of WO2010132039A1 publication Critical patent/WO2010132039A1/fr

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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 DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP 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.
  • the first section describes a MWD operating environment.
  • the second section describes different configurations for cutouts in a tool in which antennas are disposed.
  • the third section describes different configurations for sleeves that cover such cutouts.
  • the fourth section describes a wireline operating environment.
  • the fifth section provides some general comments.
  • 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.
  • 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. Alternatively or in addition, 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 may be positioned within the drill bit of the drill string. [0012] 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 essentially parallel to the face
  • the face 107 of the transducer 106 is at the outer diameter of the downhole tool 104, embodiments are not so limited.
  • 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 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 (t 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 Snell's 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, 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.
  • v acoustic velocity
  • 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. In 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. In 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 essentially parallel to the face
  • the face 207 of the transducer 206 is at the outer diameter of the downhole tool 204, embodiments are not so limited.
  • 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 21 1 to the transducer 206 and the distance from the transducer 225 to the transducer 206 are the same. In some embodiments, such distances are different.
  • the angle, ⁇ , for the transducer 211 and the transducer 225 may be the same or different. In 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 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 sO6 may operate both as a transmitter and a receiver. In operation, in some embodiments, the transducer sO6 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 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 (tA, 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 transducer 316 and a second acoustic transducer 318.
  • the dual-element transducer 306 also includes a backing material 314 for both transducers 316 and 318.
  • An acoustic matching material 320 is positioned in front of the second acoustic transducer 218 (relative to the face of the dual-element transducer 306).
  • a wear plate 312 is positioned in front of both first acoustic transducer 316 and the second acoustic transducer 318.
  • the transducer 318 may emit and detect acoustic waves.
  • the transducer 316 and the transducer 318 may emit and detect ultrasonic waves.
  • the transducer 316 and the transducer 318 may be only an emitter or a detector.
  • the transducer may be only an emitter.
  • the transducer 316 and the transducer 318 include a face 370 and a face 372, respectively. [0039] The face 370 of the transducer 316 is essentially parallel to the face
  • the face 370 of the transducer 316 is at the outer diameter of the downhole tool 304, embodiments are not so limited.
  • the transducer 316 may be embedded in the downhole tool 304 a given depth.
  • the face 372 of the transducer 318 is not parallel with the face 303 of the formation 302.
  • the transducer 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 316 and the transducer 318 is L.
  • the transducer 316 and the transducer 318 may comprise a piezoelectric ceramic or a magnetostrictive material that converts electric energy into vibration and vice versa.
  • the transducer 316 may operate both as a transmitter and a receiver. In operation, in some embodiments, the transducer 316 operates in a pulse- echo mode.
  • the transducer 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 316 then receives the reflection of the vibration off the surface 302 (the echo).
  • the transducer 316 may determine the travel time (t A ) of the reflected pulse.
  • the transducer 318 operates in a pitch-catch mode.
  • the transducer 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 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.
  • v acoustic velocity
  • 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.
  • 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.
  • FIG. 4A illustrates a drilling well during Measurement While Drilling (MWD) operations, Logging While Drilling (LWD) operations or Surface Data Logging (SDL) operations, according to some embodiments.
  • MWD Measurement While Drilling
  • LWD Logging While Drilling
  • SDL Surface Data Logging
  • 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.

Abstract

La présente invention concerne, dans certains modes de réalisation, un procédé qui consiste à émettre une première impulsion acoustique dans un fluide de forage dans un forage, en utilisant un premier transducteur acoustique dans un outil de fond, une face du premier transducteur acoustique étant à un angle qui n'est pas parallèle à une surface extérieure de l'outil de fond. Le procédé consiste à détecter la première impulsion acoustique après que la première impulsion acoustique s'est déplacée à travers le fluide de forage et est réfléchie à partir d'une paroi dans le forage, en utilisant un second transducteur acoustique dans l'outil de fond, une face du second transducteur acoustique étant approximativement parallèle à la surface extérieure de l'outil de fond. Le procédé consiste également à émettre une seconde impulsion acoustique dans le fluide de forage dans le forage, en utilisant le second transducteur acoustique. Le procédé consiste à détecter la seconde impulsion acoustique après que la seconde impulsion acoustique s'est déplacée à travers le fluide de forage et est réfléchie à partir de la paroi du forage, en utilisant le second transducteur acoustique. Le procédé consiste également à déterminer une vitesse acoustique du fluide de forage sur la base d'un temps de déplacement de la première impulsion acoustique et d'un temps de déplacement de la seconde impulsion acoustique.
PCT/US2009/002905 2009-05-11 2009-05-11 Mesures de vitesse acoustique en utilisant des transducteurs inclinés WO2010132039A1 (fr)

Priority Applications (3)

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
US13/264,336 US9631480B2 (en) 2009-05-11 2009-07-16 Acoustic velocity measurements using tilted transducers
PCT/US2009/050859 WO2010132070A1 (fr) 2009-05-11 2009-07-16 Mesures de la vitesse acoustique à l'aide de transducteurs inclinés

Applications Claiming Priority (1)

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

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NL1041744B1 (en) * 2015-06-19 2017-01-23 Halliburton Energy Services Inc Systems and methods employing an acoustic caliper tool with tool inclination correction.

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