WO2012027105A1 - Procédé de mesure de distance acoustique - Google Patents

Procédé de mesure de distance acoustique Download PDF

Info

Publication number
WO2012027105A1
WO2012027105A1 PCT/US2011/047207 US2011047207W WO2012027105A1 WO 2012027105 A1 WO2012027105 A1 WO 2012027105A1 US 2011047207 W US2011047207 W US 2011047207W WO 2012027105 A1 WO2012027105 A1 WO 2012027105A1
Authority
WO
WIPO (PCT)
Prior art keywords
acoustic
borehole
receiver
receivers
time delay
Prior art date
Application number
PCT/US2011/047207
Other languages
English (en)
Inventor
Graham Arthur Mcelhinney
Original Assignee
Smith International, 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 Smith International, Inc. filed Critical Smith International, Inc.
Priority to CA2809173A priority Critical patent/CA2809173C/fr
Publication of WO2012027105A1 publication Critical patent/WO2012027105A1/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
    • G01V1/42—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators in one well and receivers elsewhere or vice versa
    • 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
    • E21B47/02—Determining slope or direction
    • E21B47/022—Determining slope or direction of the borehole, e.g. using geomagnetism
    • E21B47/0224—Determining slope or direction of the borehole, e.g. using geomagnetism using seismic or acoustic means

Definitions

  • the present invention relates generally to drilling and surveying subterranean boreholes such as for use in oil and natural gas exploration.
  • this invention relates to a method of acoustic ranging to determine bearing and/or range to such an acoustic target, for example, during drilling of a twin well.
  • magnetic ranging can be susceptible to magnetic interference in certain applications.
  • magnetic ranging techniques are typically limited to relatively small separation distances between the twin and target wells (e.g., less than about 10 meters) unless very strong fields are utilized. [0004] Therefore there exists a need for improved ranging techniques suitable for use, for example, in well twinning and well intercept applications.
  • One aspect of this invention includes a method for acoustic surveying.
  • An acoustic pulse is transmitted into a subterranean formation from a borehole (e.g., from a transmitter deployed in the lower BHA of a drill string in a drilling well).
  • the pulse is received at first, second, and third acoustic receivers deployed in a second borehole (e.g., in a wireline tool deployed in a target well).
  • the receivers are longitudinally spaced apart from one another and at least one distance between the two wells is derived from the received pulses.
  • the receivers are circumferentially spaced apart and a toolface to target angle between the two wells is derived from the received pulses.
  • Exemplary embodiments of the present invention provide several potential advantages.
  • embodiments of the invention enable accurate determination of the distance and direction between first and second subterranean boreholes.
  • the distance and direction can be determined with a single acoustic pulse.
  • the use of a single acoustic pulse advantageously reduces noise and therefore improves ranging accuracy.
  • aspects of the invention further enable near bit (or even at bit) via deployment of an acoustic transmitter in the lower BHA of a drill string.
  • the present invention includes a method for surveying a subterranean borehole. The method includes deploying an acoustic transmitter in a first borehole and deploying first, second, and third longitudinally spaced acoustic receivers in a second borehole. The acoustic transmitter is fired to launch an acoustic pulse.
  • Corresponding acoustic waveforms are received at each of the first, second, and third acoustic receivers.
  • the received acoustic waveforms are then processed in combination with a longitudinal spacing between the first, second, and third acoustic receivers to compute a distance between the first borehole and the second borehole.
  • this invention includes a method for surveying a subterranean borehole.
  • the method includes deploying an acoustic transmitter in a first borehole and deploying first, second, and third circumferentially spaced acoustic receivers in a second borehole.
  • the acoustic transmitter is fired to launch an acoustic pulse.
  • Corresponding acoustic waveforms are received at each of the first, second, and third acoustic receivers.
  • the received acoustic waveforms are then processed to determine a toolface to target angle between the first and second boreholes.
  • FIGURE 1 depicts one example of a well twinning operation in which exemplary embodiment of the present invention may be utilized.
  • FIGURE 2 depicts a flow chart of one exemplary method embodiment in accordance with the present invention.
  • FIGURE 3 depicts one exemplary arrangement for making acoustic ranging measurements in accordance with the present invention.
  • FIGURES 4 and 5 depict schematics of exemplary triangulation calculations in accordance with the present invention.
  • FIGURE 6 depicts a flow chart of another exemplary embodiment in accordance with the present invention.
  • FIGURE 7 depicts another exemplary arrangement for making acoustic ranging measurements in accordance with the present invention.
  • FIGURE 8 depicts a schematic of another exemplary triangulation calculation in accordance with the present invention.
  • FIGURES 1 through 8 exemplary embodiments of the present invention are depicted. With respect to FIGURES 1 through 8, it will be understood that features or aspects of the embodiments illustrated may be shown from various views. Where such features or aspects are common to particular views, they are labeled using the same reference numeral. Thus, a feature or aspect labeled with a particular reference numeral on one view in FIGURES 1 through 8 may be described herein with respect to that reference numeral shown on other views.
  • FIGURE 1 depicts an exemplary well twinning operation in which a twin well 20 is being drilled approximately parallel to a target well 40.
  • the tool configuration depicted is suitable for making acoustic ranging measurements in accordance with the present invention.
  • an acoustic transmitter 32 is deployed in a bottom hole assembly (BHA) 30 which is in turn deployed in the twin well 20.
  • the acoustic transmitter 22 is preferably, although not necessarily, deployed as low in the BHA as is practical so as to advantageously provide for near-bit or even at-bit acoustic ranging measurements.
  • the BHA 30 includes a drill bit and may further include other downhole tools and sensors suitable for use in various drilling operations. The invention is not limited to such other tooling and sensors.
  • FIGURE 1 further depicts an acoustic receiving tool 50 deployed in the twin well 40.
  • receiving tool 50 includes three or more longitudinally spaced acoustic receivers 52A, 52B, and 52C deployed in a tool body.
  • Receiving tool 50 may include, for example, a conventional wireline acoustic tool including the aforementioned longitudinally spaced acoustic receivers.
  • the tool 50 may be deployed, for example, on a coiled tubing string or on a conventional wireline assembly and is preferably in electronic communication with the surface, e.g., via a conventional data-link.
  • acoustic receivers 52A, 52B, are 52C are depicted as being deployed in a tool body, they may also be deployed, for example, on corresponding extendable pads so as to contact the borehole wall.
  • the invention is not limited in these regards.
  • FIGURE 1 It will be understood by those of ordinary skill in the art that the deployment depicted on FIGURE 1 is merely exemplary for purposes of describing the invention set forth herein. It will be further understood that methods in accordance with the present invention are not limited to use in well twinning operations (as depicted). The inventive methods are equally well suited for use with substantially any other subterranean drilling operation in which ranging measurements are made between first and second wells.
  • deployment of the acoustic transmitter in the drilling well and the acoustic receivers in the target well tends to be advantageous.
  • deployment of the receivers in the target well essentially eliminates drilling noise from the received waveforms (and therefore tends to significantly increase the signal to noise ratio).
  • deployment of the receivers in the target well also promotes rapid communication with the surface, for example, via a conventional wireline data-link.
  • FIGURE 2 depicts a flow chart of one exemplary embodiment of an acoustic ranging method 100 in accordance with the present invention.
  • An acoustic transmitter is deployed in a first well at 102 (preferably the drilling well).
  • At least first, second, and third longitudinally spaced acoustic receivers are deployed in a second well at 104 (preferably the target well).
  • the acoustic transmitter is fired at 106 to propagate acoustic energy into the surrounding subterranean formation.
  • the acoustic energy is then received at 108 at each of the acoustic receivers in the second well.
  • the received energy is then processed at 110 to determine at least one distance between the first and second wells.
  • the received energy may be processed to acquire at least first and second pole angles which may be in turn further processed to obtain a distance between the acoustic transmitter and one of the acoustic receivers.
  • FIGURE 3 depicts an exemplary firing of transmitter 32 at step 106.
  • the transmitted acoustic energy enters the formation and typically induces compressional and/or shear waves therein. These acoustic waves propagate radially outward from the transmitter 32 (e.g., in substantially spherical waves). Due to the spacing between the acoustic receivers 52A, 52B, and 52C, the acoustic energy (e.g., the compressional and/or shear waves) arrives first at receiver 52A, followed by receiver 52B, and finally at receiver 52C.
  • the acoustic energy e.g., the compressional and/or shear waves
  • pole angles may be determined from the differences in arrival times of the acoustic energy at the acoustic receivers (i.e., the time delay between the arrival at a first receiver and the arrival at a second receiver). These pole angles may be determined, for example, from the time delays between various longitudinally spaced receivers and the longitudinal distances between the receivers.
  • the pole angles may be represented mathematically, for example, as follows:
  • ⁇ ⁇ and ⁇ 2 represent the computed pole angles (e.g., as depicted on FIGURE 4), v represents the velocity of sound in the formation, d represents the longitudinal separation distance between the acoustic receivers, and and At 2 represent the time delays between the first and second and second and third receivers (i.e., between receivers 52 A and 52B and between receivers 52B and 52C as depicted on FIGURE 4).
  • the speed of sound in the formation may be determined via any known means (e.g., via measurement or calculation).
  • the acoustic receivers are not necessarily equally spaced as depicted on FIGURES 3 and 4.
  • Received acoustic waveforms commonly include at least one compressional wave followed by at least one shear wave (although the invention is not limited in this regard).
  • the time delays and At 2 may be determined from the arrival times of any component (or components) of the received waveforms.
  • the time delays may be determined from the arrival times of a compressional wave. Pole angles may then be computed using the velocity of the compressional wave.
  • the time delays may be determined from the arrival times of a shear wave. Pole angles may then be computed using the velocity of the shear wave.
  • any suitable waveform processing techniques e.g., including semblance algorithms
  • the invention is not limited in these regards.
  • the aforementioned pole angles may be further processed (e.g. via triangulation calculations) to obtain one or more distances between the first and second wells.
  • distances between the acoustic transmitter 32 and the first and second receivers 52A and 52B may be represented mathematically as follows:
  • D x and D 2 represent the distances between the acoustic transmitter and the first and second receivers 52A and 52B, and ⁇ ⁇ , ⁇ 2 , and d are as defined above.
  • a transverse distance D T between the acoustic transmitter 32 and the second well 40 may also be determined (see FIGURE 5). The transverse distance is measured along a direction orthogonal (transverse) to the second well and may be thought of as being the shortest distance between the transmitter and the second well.
  • the transverse distance D T may be represented mathematically, for example, as follows:
  • FIGURE 6 depicts a flow chart of another exemplary acoustic ranging method embodiment 150 in accordance with the present invention.
  • An acoustic transmitter is deployed in a first well at 152.
  • At least first, second and third circumferentially spaced acoustic receivers are deployed in a second well at 154.
  • the acoustic transmitter is fired at 156 to propagate acoustic energy into the surrounding subterranean formation.
  • the acoustic energy is then received at 158 at each of the circumferentially spaced receivers in the second well.
  • the arrival times of the received acoustic energy may then be processed at 160 to determine a tool face to target angle (TFT) between the first and second wells.
  • TFT tool face to target angle
  • FIGURE 7 depicts a circular cross-section looking down the target well 40.
  • the twin and target wells 20 and 40 are intended to be substantially parallel.
  • the view of FIGURE 7 is also looking down the twin well 20.
  • the acoustic measuring tool 50 includes at least three circumferentially spaced, co-planar acoustic receivers 54A, 54B, and 54C.
  • the TFT may be determined from the arrival times of the acoustic energy at each of the receivers 54A, 54B, and 54C.
  • the TFT defines a direction from the target well to the transmitter in the plane of the circumferentially spaced receivers.
  • the TFT may be referenced, for example, relative to the receiver that first receives the acoustic energy (e.g., receiver 54A in FIGURE 7) or with respect to a reference direction such as magnetic north or high side.
  • TFT may be represented mathematically, for example, as follows:
  • TFT represents the tool face to target angle
  • ⁇ represents the angular separation between the acoustic transmitter and receiver 54A (i.e., the TFT referenced with respect to receiver 54A)
  • ⁇ represents an angular separation between receiver 54A and a reference direction (e.g., high side as depicted)
  • AIAB represents the time delay between reception of the acoustic wave at receiver 54A and receiver 54B
  • At A c represents the time delay between reception of the acoustic wave at receiver 54A and receiver 54C
  • At M Ax is a tool constant that represents the maximum time delay between any two receivers (A, B, or C).
  • At M Ax may be determined, for example, by dividing the speed of sound in the formation by the known distance between the receivers (e.g., the distance between receivers 54A and 54B - the length of one of the sides of equilateral triangle ABC).
  • At M Ax may also be determined empirically by rotating the sensors in the target well. In this empirical determination of At M Ax, the TFT may advantageously be determined independent of any knowledge regarding the velocity of sound in the formation.
  • At AC - At AB At BC
  • At BC represents the time delay between reception of the acoustic wave at receiver 54B and receiver 54C.
  • the angular separation ⁇ may be referenced with respect to substantially any suitable reference direction, for example, including magnetic north and the high side of the target well.
  • the angular separation ⁇ may be determined, for example, via measurements of Earth's magnetic field and/or gravitation field. Referencing the TFT with respect to a standard reference direction (such as high side) advantageously enables a simple reversal of the TFT so as to enable the direction of the target well to be determined from the measuring well.
  • a distance between the wells may also be determined by making multiple TFT angle measurements and triangulating. This may be accomplished, for example, by equipping the acoustic measurement tool 50 with multiple (e.g., first and second) longitudinally spaced sets of circumferentially spaced acoustic receivers. The TFT angles measured at each of the receiver sets may then be utilized to determine a unique triangle in three-dimensional space. The distance between the well may then be determined by applying trigonometric techniques to the measured TFT angles and the known axial distance between the receiver sets, for example, using techniques similar to those disclosed in commonly invented and commonly assigned U.S. Patent 6,985,814.
  • Acoustic ranging methods in accordance with the present invention may be advantageously utilized in various well twinning and well intercept applications (e.g., such as steam assisted gravity drainage well twinning applications and coal bed methane horizontal to vertical intercepts).
  • at least one of the distance and direction between the acoustic transmitter and receivers may be utilized to guide subsequent drilling of the drilling well (i.e., to determine a subsequent direction of drilling).
  • the transmitted acoustic wave has been assumed to be planar (i.e., as a spherical wave having an infinite radius of curvature). It will be understood to those of ordinary skill in the art that the acoustic wave may also be modeled as a spherical wave having a finite radius of curvature, for example, equal to a distance determined in a previous measurement. The invention is not limited in these regards. Those of ordinary skill in the art will further appreciate that modeling the acoustic wave as a spherical wave may provide improved accuracy when the separation distance is small (e.g., less than about 10 m).
  • the acoustic transmitter may also be deployed in the target well (e.g., in a wireline tool) and the acoustic receivers may be deployed in the measuring well (e.g., in the drill string).
  • the BHA 30 and the acoustic receiving tool 50 typically include electronic controllers.
  • the controller in the BHA 30 typically includes, for example, conventional electrical drive voltage electronics (e.g., a high voltage power supply) configured to cause the transmitter to transmits one or more pulses of acoustic energy.
  • the controller in the receiving tool 50 typically includes receiving electronics, such as a variable gain amplifier for amplifying the return signal.
  • the receiving electronics may also include various filters (e.g., pass band filters), rectifiers, multiplexers, and other circuit components for processing the return signal.
  • the controller in the receiving tool 50 may further include electronics configured to digitize the received waveforms. The digitized waveforms may then be transmitted to the surface (e.g., via a wireline data-link).
  • Suitable controllers typically further include digital programmable processors such as a microprocessor or a microcontroller and processor-readable or computer-readable programming code embodying logic, including instructions for controlling the function of the tool.
  • digital programmable processors such as a microprocessor or a microcontroller and processor-readable or computer-readable programming code embodying logic, including instructions for controlling the function of the tool.
  • any suitable digital processor may be utilized, for example, including an ADSP-2191M microprocessor, available from Analog Devices, Inc.
  • a suitable controller may also optionally include other controllable components, such as other sensors, data storage devices, power supplies, timers, and the like. The controller may also optionally be disposed to communicate with the surface.
  • logic may be represented as instructions processed by, for example, a computer, a microprocessor, hardware, firmware, programmable circuitry, or any other processing device well known in the art.
  • logic may be embodied on software suitable to be executed by a processor, as is also well known in the art.
  • the invention is not limited in this regard.
  • the software, firmware, and/or processing device may be included, for example, on a surface computer.
  • Electronic information such as logic, software, or measured or processed data may be stored in memory (volatile or non-volatile), or on conventional electronic data storage devices such as are well known in the art.

Landscapes

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

Abstract

L'invention porte sur un procédé de mesure acoustique, lequel procédé comprend le calcul d'au moins l'une d'une distance et d'une direction entre des premier et second trous de forage souterrains. Une impulsion acoustique est transmise dans une formation souterraine à partir du premier trou de forage, et reçue dans trois récepteurs espacés, ou davantage, déployés dans le second trou de forage. Une distance entre les deux trous de forage peut être déterminée à l'aide de récepteurs espacés longitudinalement, tandis qu'une direction d'une face d'outil à une cible (angle) peut être déterminée à l'aide de récepteurs espacés de façon périphérique.
PCT/US2011/047207 2010-08-26 2011-08-10 Procédé de mesure de distance acoustique WO2012027105A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
CA2809173A CA2809173C (fr) 2010-08-26 2011-08-10 Procede de mesure de distance acoustique

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US28940110A 2010-08-26 2010-08-26
US1289401 2010-08-26

Publications (1)

Publication Number Publication Date
WO2012027105A1 true WO2012027105A1 (fr) 2012-03-01

Family

ID=45723733

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2011/047207 WO2012027105A1 (fr) 2010-08-26 2011-08-10 Procédé de mesure de distance acoustique

Country Status (2)

Country Link
CA (1) CA2809173C (fr)
WO (1) WO2012027105A1 (fr)

Cited By (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20120051184A1 (en) * 2010-08-26 2012-03-01 Smith International, Inc. Method of Acoustic Ranging
WO2014097160A1 (fr) * 2012-12-18 2014-06-26 Schlumberger Technology B.V. Dispositifs, systèmes et procédés pour des investigations sismiques basse fréquence de trou de forage
US9556723B2 (en) 2013-12-09 2017-01-31 Baker Hughes Incorporated Geosteering boreholes using distributed acoustic sensing
JP2017049198A (ja) * 2015-09-04 2017-03-09 前田建設工業株式会社 切羽前方探査装置及び切羽前方探査方法
US10233742B2 (en) 2013-10-31 2019-03-19 Halliburton Energy Services, Inc. Downhole acoustic ranging utilizing gradiometric data
WO2020176102A1 (fr) * 2019-02-28 2020-09-03 Halliburton Energy Services, Inc. Alimentation d'un ensemble fond de trou par l'intermédiaire d'un train de tiges motorisé

Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4711303A (en) * 1983-10-11 1987-12-08 Shell Oil Company Method and means for determining the subsurface position of a blowing well with respect to a relief well
EP0638823A2 (fr) * 1993-08-09 1995-02-15 Baker Hughes Incorporated Dispositif à ultrasons pour mesurer une distance
EP1666698A1 (fr) * 1997-09-30 2006-06-07 Halliburton Energy Services, Inc. Localisation de la source d'un signal dans un puits de forage
CA2746078A1 (fr) * 2008-06-03 2009-12-10 Schlumberger Technology Corporation Systeme et procede permettant de determiner les positions en fond de trou

Patent Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4711303A (en) * 1983-10-11 1987-12-08 Shell Oil Company Method and means for determining the subsurface position of a blowing well with respect to a relief well
EP0638823A2 (fr) * 1993-08-09 1995-02-15 Baker Hughes Incorporated Dispositif à ultrasons pour mesurer une distance
EP1666698A1 (fr) * 1997-09-30 2006-06-07 Halliburton Energy Services, Inc. Localisation de la source d'un signal dans un puits de forage
CA2746078A1 (fr) * 2008-06-03 2009-12-10 Schlumberger Technology Corporation Systeme et procede permettant de determiner les positions en fond de trou

Cited By (10)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20120051184A1 (en) * 2010-08-26 2012-03-01 Smith International, Inc. Method of Acoustic Ranging
US8570834B2 (en) * 2010-08-26 2013-10-29 Schlumberger Technology Corporation Method of acoustic ranging
WO2014097160A1 (fr) * 2012-12-18 2014-06-26 Schlumberger Technology B.V. Dispositifs, systèmes et procédés pour des investigations sismiques basse fréquence de trou de forage
US9081110B2 (en) 2012-12-18 2015-07-14 Schlumberger Technology Corporation Devices, systems and methods for low frequency seismic borehole investigations
GB2523047A (en) * 2012-12-18 2015-08-12 Schlumberger Holdings Devices, systems and methods for low frequency seismic borehole investigations
US10233742B2 (en) 2013-10-31 2019-03-19 Halliburton Energy Services, Inc. Downhole acoustic ranging utilizing gradiometric data
US9556723B2 (en) 2013-12-09 2017-01-31 Baker Hughes Incorporated Geosteering boreholes using distributed acoustic sensing
JP2017049198A (ja) * 2015-09-04 2017-03-09 前田建設工業株式会社 切羽前方探査装置及び切羽前方探査方法
WO2020176102A1 (fr) * 2019-02-28 2020-09-03 Halliburton Energy Services, Inc. Alimentation d'un ensemble fond de trou par l'intermédiaire d'un train de tiges motorisé
US11174708B2 (en) 2019-02-28 2021-11-16 Halliburton Energy Services, Inc. Power downhole tool via a powered drill string

Also Published As

Publication number Publication date
CA2809173A1 (fr) 2012-03-01
CA2809173C (fr) 2015-10-06

Similar Documents

Publication Publication Date Title
US8547788B2 (en) Methods for making acoustic anisotropy logging while drilling measurements
CA2809173C (fr) Procede de mesure de distance acoustique
EP2841692B1 (fr) Détection d'emplacement de limite de plusieurs couches placées sous la surface
AU2014398251B2 (en) Reluctance sensor for measuring a magnetizable structure in a subterranean environment
AU2011375008B2 (en) Improved casing detection tools and methods
US8788207B2 (en) Precise borehole geometry and BHA lateral motion based on real time caliper measurements
AU2013338324B2 (en) Passive magnetic ranging for SAGD and relief wells via a linearized trailing window Kalman filter
NO20160556A1 (en) Downhole triaxial electromagnetic ranging
US8570834B2 (en) Method of acoustic ranging
EP2749906A1 (fr) Détermination de l'orientation de capteur sismique dans un puits de forage
WO2012021393A2 (fr) Lenteur d'ondes de cisaillement à basse fréquence dans une formation à partir de données dérivant d'un bruit de forage et obtenues grâce à un réseau quadripolaire
NL1041915B1 (en) Passive ranging using acoustic energy originating from a target wellbore
US10222506B2 (en) System and methodology for orientation of a borehole seismic source
US10233742B2 (en) Downhole acoustic ranging utilizing gradiometric data
WO2017127117A1 (fr) Procédés et systèmes utilisant un agencement de capteurs de gradient pour télémétrie
US20230213677A1 (en) Through tubing cement evaluation based on rotatable transmitter and computational rotated responses
EP3298237B1 (fr) Évaluation de pendage réel, d'azimut réel et de qualité de données d'une formation par diagraphie de conductivité à composantes multiples et diagraphie directionnelle

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: 11820362

Country of ref document: EP

Kind code of ref document: A1

ENP Entry into the national phase

Ref document number: 2809173

Country of ref document: CA

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 11820362

Country of ref document: EP

Kind code of ref document: A1