+

WO1996009561A1 - Appareil permettant de localiser un capteur - Google Patents

Appareil permettant de localiser un capteur Download PDF

Info

Publication number
WO1996009561A1
WO1996009561A1 PCT/GB1995/002234 GB9502234W WO9609561A1 WO 1996009561 A1 WO1996009561 A1 WO 1996009561A1 GB 9502234 W GB9502234 W GB 9502234W WO 9609561 A1 WO9609561 A1 WO 9609561A1
Authority
WO
WIPO (PCT)
Prior art keywords
signal
sensor
channel
channel means
oil
Prior art date
Application number
PCT/GB1995/002234
Other languages
English (en)
Inventor
Erhard Lothar Edgar Kluth
Malcolm Paul Varnham
Original Assignee
Sensor Dynamics Limited
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 Sensor Dynamics Limited filed Critical Sensor Dynamics Limited
Priority to AU35272/95A priority Critical patent/AU3527295A/en
Publication of WO1996009561A1 publication Critical patent/WO1996009561A1/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
    • E21B47/09—Locating or determining the position of objects in boreholes or wells, e.g. the position of an extending arm; Identifying the free or blocked portions of pipes
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/001—Acoustic presence detection

Definitions

  • the invention relates to apparatus for determining the location of sensors within channels.
  • the invention is especially relevant in the oil industry for determining the location of sensors which have been pumped into oil and gas wells.
  • Optical fibre sensors together with optical fibre cables to link the sensor to the measurement instrumentation, are being developed for this purpose since they offer specific advantages, particularly in the ability to withstand extremes of high pressure and temperature. Furthermore, such optical fibre sensors may be of a structure and diameter similar to those of the optical fibre cable itself. Sensors are being developed which can be remotely deployed into oil wells through conveniently sized hydraulic tubing.
  • the only known methods for determining the location of a sensor within a channel such, for example, as hydraulic tubing is either to measure the length of fibre cable which has been deployed into the channel or to employ a docking mechanism which enables the sensor to be locked in position when it reaches its desired location.
  • the former method is not believed to be sufficiently accurate, and the latter method places certain restrictions on sensor design.
  • An aim of the present invention is to allow a wide variety of sensors to be located accurately in channels.
  • the present invention provides apparatus for determining the location of a sensor within channel means, which apparatus comprises signal means by which an appropriate signal can be applied to the channel means, and processing means for measuring the time difference between a signal from the signal means and a measured signal from the sensor.
  • the apparatus may include sensor communication means for communicating the signal from the sensor to the signal processing means.
  • the signal means may be a piezoelectric element which produces the signal in the form of an acoustic signal.
  • the channel means may be narrow bore hydraulic tubing filled with fluid.
  • the fluid may be a liquid or a gas.
  • the apparatus may include the sensor.
  • the sensor may be an optical fibre sensor.
  • the sensor communication means may include an optical fibre cable, sensor readout electronics, and an electric cable.
  • the processing means may be an oscilloscope for displaying both the signal from the signal means and the measured signal from the sensor.
  • the location of the sensor down the channel means may be determined from the time delay which can be measured from the oscilloscope.
  • the apparatus includes second channel means, and is one in which the signal from the signal means is applied to the second channel means. Energy from the signal propagated down the second channel means is coupled to the first channel means by signal coupling means. Signals from the sensor and a signal detection means are O 96/ 9561 P
  • the first channel means may be hydraulic conduit attached, for example strapped, to the outside of the second channel means.
  • the second channel means may be production tubing through which oil and/or gas flows up to the surface from an oil or gas reservoir.
  • the signal applied to the second channel means may be an acoustic signal generated by a piezoelectric element, of such a frequency that it may be transmitted through the second channel means without suffering undue attenuation.
  • the apparatus may include signal coupling means, for example straps, which are used to fix the first channel means, for example hydraulic tubing, to the outside of the second channel means.
  • the apparatus may include signal detection means in the form of an acoustic sensor attached, for example strapped, to a known location on the side of the second channel means.
  • the sensor may be a single acoustic sensor, a number of independent acoustic sensors, or an array of linked acoustic sensors.
  • the processing means may include digital signal processing means in order to average the signals received from the apparatus and thereby improve the accuracy of the sensor location. Where there is more than one sensor, then the processing means may include means for locating each sensor based upon the timing information between the detected signal from the respective sensor and the signal detection means.
  • the apparatus includes second channel means, and is one in which the sensor is a distributed temperature sensor, which is able to measure temperature at many points along the first channel means.
  • the apparatus may include valve means, and may be one in which signal means provides a control signal to open the valve means which allows material, such as oil or gas having a different temperature, to flow up the second channel means.
  • the apparatus may include one or more thermal path means between the second channel means and the first channel means in order to communicate the temperature to the first channel means.
  • the first channel means may be hydraulic tubing which is thermally lagged between the discrete thermal path means in order to provide a signature in the measured response from the distributed temperature sensor corresponding to the locations of the thermal path means.
  • the second channel means may be production tubing in an oil or gas reservoir.
  • the thermal path means may be straps used to strap the second channel means to the first channel means.
  • the location of the distributed temperature sensor with respect to the second channel means may be determined by inspecting the measured temperature profile where the locations of the thermal strap means will be clearly visible.
  • the apparatus includes reflection means, for example positioned at the end of the channel means.
  • the signal applied by the signal means to the channel means can be measured by the signal detection means and then measured again after reflection.
  • the processing means can thus reference the location of the sensor by centering the signal received from the sensor within the window of the first and second signals received from the signal detection means.
  • the channel means may be hydraulic conduit filled with hydraulic oil and attached, for example strapped, to the outside of production tubing in an oil well.
  • the reflection means may be a termination at the end of the channel means, or may be the transition between two sections of tubing having different diameters.
  • the signal means may be a pump which is able to provide a step input of pressure to the channel means.
  • the signal detection means may be a pressure sensor which measures the pressure within the channel means.
  • the sensor may be an optical fibre pressure sensor which has been pumped down the hydraulic conduit. It will be appreciated that this technique can be used to determine the position of such a pressure sensor as it is pumped along a hydraulic conduit. Such an application could be improved by the provision of a number of partial reflection means at intervals along the hydraulic conduit. It will also be appreciated that a sensor having an acoustic response would detect any noise reflected by the partial reflection means as the sensor passes along the channel. This noise may be enhanced deliberately by devices fixed to the channel which strike the side of the channel, or interrupt the fluid flow, thereby making a distinctive noise.
  • reflection means may also be added to second channel means, to which the first channel means may be attached. Signals transmitted down the second channel means and reflected from the reflection means would be detected in the channel means.
  • the second channel means may be production tubing in an oil or gas well.
  • the apparatus includes first signal detection means which is located at one end of the channel means, and second signal detection means which is located at the other end of the channel means. The signal means applies a time-varying signal to the channel means, and the location of the sensor is determined in the processing means by measuring the phase shift between signals measured by the first and second signal detection means and the sensor.
  • the signal means may be a pump applying pressure which varies sinusoidally to the channel means
  • the first and second signal detection means may be pressure gauges.
  • the sensor may be a pressure sensor.
  • the signal processing means may be a vector voltmeter.
  • ambiguities in sensor location may be resolved by applying different frequencies measuring the phase shift between the sensor and the first and second signal detection means at different signal frequencies.
  • Figure 1 is a diagram of an embodiment of the present invention in which a signal is applied to channel means
  • Figure 2 is a diagram of an embodiment of the present invention where the signal is applied to second channel means in an oil well;
  • Figure 3 is a diagram of an embodiment of the present invention allowing the location of a distributed temperature sensor
  • Figure 4 is a diagram of an embodiment of the present invention in which a signal is reflected back towards signal means from reflection means at the end of channel means; and
  • Figure 5 is a diagram of an embodiment of the present invention where a signal detection means is placed at both ends of the channel means.
  • signal means 1 is employed to propagate an appropriate signal along channel means 2, the signal also being an output to processing means 3.
  • a sensor 4 is situated within the channel means 2 and the detected signal from the sensor 4 is communicated back to the processing means 3 by means of an appropriate sensor communication means 5.
  • the apparatus shown in Figure 1 may be used to determine the location of a sensor 4 such as an optical fibre pressure sensor which has been pumped along the channel means 2.
  • the channel means 2 may in this example be a length of hydraulic control line of 1/4" (6 mm) diameter attached to the outside of the production string of an oil or gas well through which oil or gas flows from the reservoir to the surface.
  • the sensor communication means 5 may comprise a length of optical fibre cable which connects the optical fibre pressure sensor to its instrumentation.
  • the hydraulic steel control line is filled with a first fluid such as water.
  • the signal propagated along the hydraulic steel control line comprises flowing a second fluid such as dry nitrogen at a measured pressure and flow rate through the hydraulic steel control line.
  • the processing means 3 may use the time difference from the application of the second fluid to a measured discontinuity in the output of the pressure sensor within the hydraulic steel control line in order to locate the position of the pressure sensor.
  • the applied pressure may be approximately constant in order to simplify the detection of the measured discontinuity in the output of the pressure sensor. It would be convenient to measure the volume of fluid expelled from the hydraulic steel control line in order to calibrate the measurement. The calibration would need to take into account changes in the density of fluids with temperature and pressure.
  • the temperature distribution may be measured by pumping a suitable optical fibre along the hydraulic steel control line and using a distributed temperature profiling instrumentation (such as a York DTS 80) to output the temperature profile.
  • signal means 1 is employed to propagate an appropriate signal along second channel means 21 to which first channel means 24 is attached.
  • Energy from the signal propagating down the second channel means 21 is coupled to the first channel means 24 by signal coupling means 23, and measured by signal detection means 22.
  • Signals from the sensor 4 and the signal detection means 22 are passed to the processing means 3 in order to determine the location of the sensor 4 relative to the second channel means 21.
  • the sensor 4 is a distributed temperature sensor 31 allowing the temperature profile along the first channel means 24 to be measured.
  • the signal means 1 provides a control signal to open valve means
  • thermal path means 33 between the second channel means 21 and the first channel means 24 in order to communicate the temperature change to the first channel means 24.
  • the locations of the thermal path means 33 will be visible on the measured response from the distributed temperature sensor 31. Location is provided by reference to the known hardware design of the oil or gas well.
  • the signal applied by the signal means 1 to the channel means 2 can be measured by the signal detection means 22 and then measured again when it is reflected back.
  • the processing means 3 can thus reference the location of the sensor 4 by centering the signal received from the sensor 4 within the window of the signals received from the signal detection means 22.
  • first signal detection means 51 is located at one end of the channel means 2
  • second signal detection means 52 is located at the other end of the channel means 2.
  • the signal means 1 applies a time-varying signal to the channel means 2, and the location of the sensor is determined in the processing means 3 by measuring the phase shift between signals measured by first and second signal detection means 51,52 and the sensor 4.

Landscapes

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

Abstract

L'invention porte sur un appareil servant à localiser un capteur (4) dans des conduits (2). Cet appareil comprend des moyens d'émission d'un signal (1) susceptibles d'envoyer un signal dans des conduits (2) ainsi que des moyens de traitement (3) pour mesurer le décalage existant entre un signal émis par les moyens d'émission (1) et un signal enregistré en provenance du capteur (4).
PCT/GB1995/002234 1994-09-21 1995-09-20 Appareil permettant de localiser un capteur WO1996009561A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
AU35272/95A AU3527295A (en) 1994-09-21 1995-09-20 Apparatus for sensor location

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GB9419031A GB9419031D0 (en) 1994-09-21 1994-09-21 Apparatus for sensor location
GB9419031.1 1994-09-21

Publications (1)

Publication Number Publication Date
WO1996009561A1 true WO1996009561A1 (fr) 1996-03-28

Family

ID=10761685

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/GB1995/002234 WO1996009561A1 (fr) 1994-09-21 1995-09-20 Appareil permettant de localiser un capteur

Country Status (3)

Country Link
AU (1) AU3527295A (fr)
GB (1) GB9419031D0 (fr)
WO (1) WO1996009561A1 (fr)

Cited By (13)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5754495A (en) * 1996-05-13 1998-05-19 Halliburton Energy Services, Inc. Method for acoustic determination of the length of a fluid conduit
WO1998050681A1 (fr) * 1997-05-02 1998-11-12 Baker Hughes Incorporated Puits utilisant des detecteurs et des equipements operationnels a base de fibres optiques
WO2003041282A3 (fr) * 2001-11-07 2004-02-26 Baker Hughes Inc Appareil et procede de communication bidirectionnelle semi-passive dans un trou de forage
WO2005024182A1 (fr) * 2003-09-05 2005-03-17 Schlumberger Technology B.V. Systeme de telemesure pour puits
GB2411673A (en) * 2004-03-01 2005-09-07 Zenith Oilfield Technology Ltd Apparatus and method for measuring the position of a portion of a pump assembly
US7040390B2 (en) 1997-05-02 2006-05-09 Baker Hughes Incorporated Wellbores utilizing fiber optic-based sensors and operating devices
US7348893B2 (en) 2004-12-22 2008-03-25 Schlumberger Technology Corporation Borehole communication and measurement system
WO2009004333A1 (fr) * 2007-07-03 2009-01-08 Schlumberger Technology B.V. Procédé de localisation d'un récepteur dans un puits
WO2012010821A3 (fr) * 2010-07-19 2013-02-21 Halliburton Energy Services, Inc. Communication à travers la gaine d'une ligne
US8573313B2 (en) 2006-04-03 2013-11-05 Schlumberger Technology Corporation Well servicing methods and systems
US8930143B2 (en) 2010-07-14 2015-01-06 Halliburton Energy Services, Inc. Resolution enhancement for subterranean well distributed optical measurements
US9664011B2 (en) 2014-05-27 2017-05-30 Baker Hughes Incorporated High-speed camera to monitor surface drilling dynamics and provide optical data link for receiving downhole data
US9823373B2 (en) 2012-11-08 2017-11-21 Halliburton Energy Services, Inc. Acoustic telemetry with distributed acoustic sensing system

Citations (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
SU711280A1 (ru) * 1976-06-18 1980-01-25 Tarakanov Valerij A Способ определени глубины в скважине
EP0084468A1 (fr) * 1982-01-12 1983-07-27 Thomson-Csf Système de positionnement acoustique
US4637463A (en) * 1984-08-02 1987-01-20 Mccoy James N Echo ranging gun
GB2208004A (en) * 1987-08-12 1989-02-15 Michael Owen A signal propagation technique for distance measurement
SU1470943A1 (ru) * 1987-07-15 1989-04-07 Всесоюзный научно-исследовательский институт нефтепромысловой геофизики Способ определени глубины залегани пересеченных скважиной геологических формаций
JPH02118448A (ja) * 1988-10-28 1990-05-02 Hitachi Ltd 管内検査システム、管内検査結果表示方法
EP0464346A1 (fr) * 1990-06-12 1992-01-08 Strabag Ag Dispositif pour déterminer des déformations linéaires d'un milieu le long d'une section de mesure
GB2283035A (en) * 1993-10-25 1995-04-26 Camco Int Coiled tubing with signal transmitting passageway
GB2284257A (en) * 1993-11-26 1995-05-31 Sensor Dynamics Ltd Remote measurement of physical parameters

Patent Citations (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
SU711280A1 (ru) * 1976-06-18 1980-01-25 Tarakanov Valerij A Способ определени глубины в скважине
EP0084468A1 (fr) * 1982-01-12 1983-07-27 Thomson-Csf Système de positionnement acoustique
US4637463A (en) * 1984-08-02 1987-01-20 Mccoy James N Echo ranging gun
SU1470943A1 (ru) * 1987-07-15 1989-04-07 Всесоюзный научно-исследовательский институт нефтепромысловой геофизики Способ определени глубины залегани пересеченных скважиной геологических формаций
GB2208004A (en) * 1987-08-12 1989-02-15 Michael Owen A signal propagation technique for distance measurement
JPH02118448A (ja) * 1988-10-28 1990-05-02 Hitachi Ltd 管内検査システム、管内検査結果表示方法
EP0464346A1 (fr) * 1990-06-12 1992-01-08 Strabag Ag Dispositif pour déterminer des déformations linéaires d'un milieu le long d'une section de mesure
GB2283035A (en) * 1993-10-25 1995-04-26 Camco Int Coiled tubing with signal transmitting passageway
GB2284257A (en) * 1993-11-26 1995-05-31 Sensor Dynamics Ltd Remote measurement of physical parameters

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
PATENT ABSTRACTS OF JAPAN vol. 014, no. 340 (P - 1080) 23 July 1990 (1990-07-23) *

Cited By (29)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5754495A (en) * 1996-05-13 1998-05-19 Halliburton Energy Services, Inc. Method for acoustic determination of the length of a fluid conduit
US7040390B2 (en) 1997-05-02 2006-05-09 Baker Hughes Incorporated Wellbores utilizing fiber optic-based sensors and operating devices
US8789587B2 (en) 1997-05-02 2014-07-29 Baker Hughes Incorporated Monitoring of downhole parameters and tools utilizing fiber optics
GB2339902A (en) * 1997-05-02 2000-02-09 Baker Hughes Inc Monitoring of downhole parameters and tools utilizing fiber optics
US6268911B1 (en) 1997-05-02 2001-07-31 Baker Hughes Incorporated Monitoring of downhole parameters and tools utilizing fiber optics
GB2339902B (en) * 1997-05-02 2002-01-23 Baker Hughes Inc Monitoring of downhole parameters
US6588266B2 (en) 1997-05-02 2003-07-08 Baker Hughes Incorporated Monitoring of downhole parameters and tools utilizing fiber optics
WO1998050680A3 (fr) * 1997-05-02 1999-02-04 Baker Hughes Inc Surveillance de parametres et d'outils de fond de puits au moyen de fibres optiques
WO1998050681A1 (fr) * 1997-05-02 1998-11-12 Baker Hughes Incorporated Puits utilisant des detecteurs et des equipements operationnels a base de fibres optiques
US7201221B2 (en) 1997-05-02 2007-04-10 Baker Hughes Incorporated Wellbores utilizing fiber optic-based sensors and operating devices
GB2398095B (en) * 2001-11-07 2006-04-05 Baker Hughes Inc Semi-passive two way borehole communication apparatus and method
GB2398095A (en) * 2001-11-07 2004-08-11 Baker Hughes Inc Passive two way borehole communication apparatus and method
WO2003041282A3 (fr) * 2001-11-07 2004-02-26 Baker Hughes Inc Appareil et procede de communication bidirectionnelle semi-passive dans un trou de forage
US7990282B2 (en) 2003-09-05 2011-08-02 Schlumberger Technology Corporation Borehole telemetry system
WO2005024182A1 (fr) * 2003-09-05 2005-03-17 Schlumberger Technology B.V. Systeme de telemesure pour puits
US8009059B2 (en) 2003-09-05 2011-08-30 Schlumberger Technology Corporation Downhole power generation and communications apparatus and method
GB2411673B (en) * 2004-03-01 2007-12-05 Zenith Oilfield Technology Ltd Apparatus and method for measuring a position of a portion of a pump assembly
GB2411673A (en) * 2004-03-01 2005-09-07 Zenith Oilfield Technology Ltd Apparatus and method for measuring the position of a portion of a pump assembly
US7348893B2 (en) 2004-12-22 2008-03-25 Schlumberger Technology Corporation Borehole communication and measurement system
US8573313B2 (en) 2006-04-03 2013-11-05 Schlumberger Technology Corporation Well servicing methods and systems
WO2009004333A1 (fr) * 2007-07-03 2009-01-08 Schlumberger Technology B.V. Procédé de localisation d'un récepteur dans un puits
US9158020B2 (en) 2007-07-03 2015-10-13 Schlumberger Technology Corporation Method of locating a receiver in a well
US8930143B2 (en) 2010-07-14 2015-01-06 Halliburton Energy Services, Inc. Resolution enhancement for subterranean well distributed optical measurements
WO2012010821A3 (fr) * 2010-07-19 2013-02-21 Halliburton Energy Services, Inc. Communication à travers la gaine d'une ligne
US8584519B2 (en) 2010-07-19 2013-11-19 Halliburton Energy Services, Inc. Communication through an enclosure of a line
US9003874B2 (en) 2010-07-19 2015-04-14 Halliburton Energy Services, Inc. Communication through an enclosure of a line
RU2564040C2 (ru) * 2010-07-19 2015-09-27 Хэллибертон Энерджи Сервисиз, Инк. Связь через защитную оболочку линии
US9823373B2 (en) 2012-11-08 2017-11-21 Halliburton Energy Services, Inc. Acoustic telemetry with distributed acoustic sensing system
US9664011B2 (en) 2014-05-27 2017-05-30 Baker Hughes Incorporated High-speed camera to monitor surface drilling dynamics and provide optical data link for receiving downhole data

Also Published As

Publication number Publication date
GB9419031D0 (en) 1994-11-09
AU3527295A (en) 1996-04-09

Similar Documents

Publication Publication Date Title
US6550345B1 (en) Technique for measurement of gas and liquid flow velocities, and liquid holdup in a pipe with stratified flow
US7152490B1 (en) Methods for determining transducer delay time and transducer separation in ultrasonic flow meters
US6945095B2 (en) Non-intrusive multiphase flow meter
US6813962B2 (en) Distributed sound speed measurements for multiphase flow measurement
US6601458B1 (en) Distributed sound speed measurements for multiphase flow measurement
US5179862A (en) Snap-on flow measurement system
US6575043B1 (en) Method and apparatus for characterizing flows based on attenuation of in-wall propagating wave modes
KR100492308B1 (ko) 초음파 유량 측정 방법
US6209388B1 (en) Ultrasonic 2-phase flow apparatus and method
WO1996009561A1 (fr) Appareil permettant de localiser un capteur
US6769293B2 (en) Detection of liquid in gas pipeline
CA2477659A1 (fr) Debitmetre a section de tube elargie et mesure de pression differentielle sensible
US20110271769A1 (en) Flow measuring apparatus
CA2743500C (fr) Procede et appareil de mesure de composition et de debits d'un gaz humide
KR940009689A (ko) 유속측정장치
NO339488B1 (no) Anordning og fremgangsmåte for måling av en parameter i en multifasestrømning
WO2008117030A1 (fr) Appareil de mesure d'écoulement utilisant des ondes de tube et procédé correspondant
EP0536313A1 (fr) Systeme de mesure d'ecoulement ameliore
CA2621313C (fr) Transducteur de pression avec capteur de pression acoustique
US20040086623A1 (en) Storage stable pan release coating and cleaner
CA2700299C (fr) Mandrin deployable pour mesures de fond
EP2758757B1 (fr) Appareil de test de petit volume et procédé de mesure de débit
US7168311B2 (en) Fiber optic monitoring of flow inside and outside a tube downhole
CN111947722A (zh) 体积及质量流量检测方法及装置
US20240310197A1 (en) Acoustic Rail for Clamp on Ultrasonic Flow Meter

Legal Events

Date Code Title Description
AK Designated states

Kind code of ref document: A1

Designated state(s): AM AT AU BB BG BR BY CA CH CN CZ DE DK EE ES FI GB GE HU IS JP KE KG KP KR KZ LK LR LT LU LV MD MG MK MN MW MX NO NZ PL PT RO RU SD SE SG SI SK TJ TM TT UA UG US UZ VN

AL Designated countries for regional patents

Kind code of ref document: A1

Designated state(s): KE MW SD SZ UG AT BE CH DE DK ES FR GB GR IE IT LU MC NL PT SE BF BJ CF CG CI CM GA GN ML MR NE SN TD TG

DFPE Request for preliminary examination filed prior to expiration of 19th month from priority date (pct application filed before 20040101)
121 Ep: the epo has been informed by wipo that ep was designated in this application
REG Reference to national code

Ref country code: DE

Ref legal event code: 8642

122 Ep: pct application non-entry in european phase
NENP Non-entry into the national phase

Ref country code: CA

点击 这是indexloc提供的php浏览器服务，不要输入任何密码和下载