WO2010060040A1 - Imageur 3d pour trou de sonde - Google Patents

Imageur 3d pour trou de sonde Download PDF

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Publication number
WO2010060040A1
WO2010060040A1 PCT/US2009/065537 US2009065537W WO2010060040A1 WO 2010060040 A1 WO2010060040 A1 WO 2010060040A1 US 2009065537 W US2009065537 W US 2009065537W WO 2010060040 A1 WO2010060040 A1 WO 2010060040A1
Authority
WO
WIPO (PCT)
Prior art keywords
tool
borehole
transmitter
antenna
image
Prior art date
Application number
PCT/US2009/065537
Other languages
English (en)
Inventor
Michael S. Bittar
Jing Li
Stephen Zannoni
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 US13/061,759 priority Critical patent/US9411068B2/en
Priority to GB1104663.8A priority patent/GB2475456B/en
Publication of WO2010060040A1 publication Critical patent/WO2010060040A1/fr

Links

Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
    • G01V3/30—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with electromagnetic waves
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/08—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation operating with magnetic or electric fields produced or modified by objects or geological structures or by detecting devices
    • G01V3/10—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation operating with magnetic or electric fields produced or modified by objects or geological structures or by detecting devices using induction coils
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging

Definitions

  • BACKGROUND Oil field operators seek as much information as possible regarding parameters and conditions encountered downhole. Such information typically includes characteristics of the earth formations traversed by the borehole, and data relating to the size and configuration of the borehole itself.
  • the collection of information relating to conditions downhole which commonly is referred to as "logging,” can be performed by several methods including wireline logging, “logging while drilling” (LWD), dnllpipe conveyed logging, and coil tubmg conveyed logging.
  • a probe or "sonde” In wireline logging, a probe or "sonde” is lowered into the borehole after some or all of the well has been drilled.
  • the sonde hangs at the end of a long cable or “wireline” that provides mechanical support to the sonde and also provides an electrical connection between the sonde and electrical equipment located at the surface of the well.
  • various parameters of the earth's formations are measured and correlated with the position of the sonde in the borehole as the sonde is pulled uphole.
  • the drilling assembly includes sensing instruments that measure various parameters as the formation is being penetrated. While LWD techniques allow more contemporaneous formation measurements, drilling operations create an environment that is generally hostile to electronic instrumentation and sensor operations
  • sensing instruments are mounted on a tubing string, which moves the instrument package through an existing borehole.
  • the tubmg string enables logging of horizontal well bores without requiring the sensing instruments to tolerate the hostile drilling environment.
  • the measurement data is stored in internal memory and recovered along with the instrument package.
  • a few existing logging tools offer measurements as a function of depth and rotational angle, enabling a driller to see, e.g., an image of the borehole wall.
  • a very few existing logging tools offer measurements as a function of depth and radial distance from the borehole (e g., induction tools having multiple depths of investigation). While each of these tools is useful to some degree, they leave the driller with an incomplete picture of the situation downhole.
  • FIG. 1 shows an illustrative logging while drilling (LWD) environment
  • Fig. 2 shows an illustrative wireline logging environment
  • Fig. 3 shows an illustrative LWD tool having a first antenna arrangement suitable for 3D imaging
  • Fig. 4 shows an illustrative LWD tool having a second antenna arrangement suitable for
  • Fig. 5A shows an illustrative broadband horn antenna
  • Fig. 5B shows a resistively loaded bowtie antenna
  • Fig. 6 is a block diagram of illustrative tool electronics
  • Fig. 7 shows illustrative 3D image measurement contributions
  • Fig. 8 shows an illustrative transmit pulse
  • Fig. 9 shows an illustrative receive signal
  • Fig. 10 shows an illustrative 3D image.
  • a 3D imaging tool rotates, transmitting pulses that are approximately a nanosecond long and measuring the time it takes to receive reflections of these pulses.
  • Multiple receivers are employed to provide accurate triangulation of the reflectors.
  • multiple transmitters are employed to obtain compensated measurements, i.e., measurements that compensate for variations in the receiver electronics. Because reflections occur at boundaries between materials having different dielectric constants, the 3D imaging tool can map out such boundaries in the neighborhood of the borehole.
  • Fig. 1 shows an illustrative logging-while-drilling ("LWD") environment.
  • a drilling platform 2 supports a derrick 4 having a traveling block 6 for raising and lowering a drill string 8.
  • a top drive 10 supports and rotates the drill string 8 as it is lowered through the wellhead 12.
  • a drill bit 14 is driven by a downhole motor and/or rotation of the drill string 8.
  • a pump 18 circulates drilling fluid 20 through a feed pipe 22, through the interior of the drill string 8 to drill bit 14.
  • the fluid exits through orifices in the drill bit 14 and flows upward through the annulus around the drill string 8 to transport drill cuttings to the surface, where the fluid is filtered and recirculated.
  • the drill bit 14 is just one piece of a bottom-hole assembly that includes one or more drill collars (thick- walled steel pipe) to provide rigidity and add weight to aid the drilling process. Some of these drill collars include built-in logging instruments to gather measurements of various drilling parameters such as position, orientation, weight-on-bit, borehole diameter, etc.
  • the tool orientation may be specified in terms of a tool face angle (rotational orientation), an inclination angle (the slope), and compass direction, each of which can be derived from measurements by magnetometers, inclinometers, and/or accelerometers, though other sensor raa KRUEGER
  • the tool includes a 3 -axis fluxgate magnetometer and a 3 -axis accelerometer.
  • the combination of those two sensor systems enables the measurement of the tool face angle, inclination angle, and compass direction.
  • Such orientation measurements can be combined with gyroscopic or mertial measurements to accurately track tool position.
  • a LWD 3D imaging tool 24 can be included in the bottom-hole assembly near the bit 14. As the bit extends the borehole through the formations, 3D imaging tool 26 rotates and collects azimuthally-dependent reflection measurements that a downhole controller associates with tool position and orientation measurements to form a 3D image map of the borehole neighborhood. The measurements can be stored in internal memory and/or communicated to the surface.
  • a telemetry sub 26 may be included in the bottom-hole assembly to maintain a communications link with the surface. Mud pulse telemetry is one common telemetry technique for transferring tool measurements to surface receivers and receiving commands from the surface, but other telemetry techniques can also be used.
  • a data acquisition module 36 receives the uplink signal from the telemetry sub 26.
  • Module 36 optionally provides some preliminary processing and digitizes the signal.
  • a data processing system 50 (shown in Fig. 1 as a computer) receives a digital telemetry signal, demodulates the signal, and displays the tool data or well logs to a user.
  • Software (represented in Fig. 1 as information storage media 52) governs the operation of system 50
  • a user interacts with system 50 and its software 52 via one or more input devices 54 and one or more output devices 56.
  • the drill string 8 may be removed from the borehole as indicated in Fig. 2
  • logging operations can be conducted using a wireline logging tool 34, i.e., a sensing instrument sonde suspended by a cable 42 having conductors for transporting power to the tool and telemetry from the tool to the surface.
  • a dielectric logging portion of the logging tool 34 may have sensing pads 36 that slide along the borehole wall as the tool is pulled uphole.
  • a logging facility 44 collects measurements from the logging tool 34, and includes computing facilities for processing and storing the measurements gathered by the logging tool.
  • Fig. 3 shows a side view of an illustrative LWD tool 302 having a first antenna arrangement suitable for 3D imaging.
  • the electronics behind faceplate 304 are coupled to a raa KRUEGER
  • an alternative LWD tool 402 has a second antenna arrangement suitable for 3D imaging.
  • three receivers 408, 410, and 412 are positioned in a row between two transmitters 404 and 406. This antenna arrangement enables compensated measurements to be made and improves measurement reliability because more information is available that can be used to correct for environmental effects.
  • the second antenna arrangement provides a degree of redundancy that enables the tool to continue operating even if one of the receivers and one of the transmitters fail.
  • each sensing surface will trace a helical path on the borehole wall.
  • Orientation sensors withm the tool can be used to associate the measurements with the sensors' positions on the borehole wall.
  • Electronics within the tool can aggregate measurements versus position to form a detailed map (or 3D image) of the borehole wall, which can be stored for later retrieval or compressed and transmitted to the surface for timely use by the drilling team If sufficient telemetry bandwidth is available, surface computing facilities can collect formation property measurements, orientation (azimuth) measurements, and tool position measurements, and process the collected measurements to create and display the map (or 3D image) Though the antenna arrangements of Figs.
  • the antennas can be mounted on a rotating head to enable scanning in each direction.
  • multiple azimuthally-spaced antennas can be employed to enable scanning in different directions without requiring antenna and/or tool rotation.
  • the antennas can take the form of ridged microwave horns such as that shown in Fig. 5A, or the form of resistively loaded bowtie antennas as shown in Fig. 5B. In the isometric scale drawing of Fig.
  • the overall dimensions of the antenna horn 702 are about 2.5 cm high, 3.8 cm wide, and 4.0 cm deep, including the rectangular feed chamber 704
  • the antenna bandwidth is increased by the presence of two ridges 706 extending from the feed point to the aperture.
  • a coaxial cable 708 is used to drive the antenna.
  • the mterior of the horn 702 is filled with a dielectric material having a relative permittivity between 1 and 100.
  • the bowtie antenna shown in Fig. 5B has two conductive elements 722 mounted on a pad of microwave-absorbing material 724.
  • the conductive elements have a generally triangular shape with an opening angle ⁇ of about 60°.
  • the combined length of the conductive elements, L is greater than or equal to half of the pulse span in space
  • a tool operating with a pulse width of IxIO "9 s in an environment where the speed of light c is 2.8x10 8 m/s would have an overall length L greater than or equal to about 14 cm.
  • the microwave-absorbing material provides resistive loading to broaden the bandwidth of the antenna, and it further acts to reduce the influence of the conductive tool body on the performance of the antenna.
  • the bowtie antenna structure can in many cases be easier to manufacture and install than the horn antenna.
  • Fig. 6 shows a block diagram of the electronics for an illustrative 3D imaging tool.
  • the tool electronics include a system clock and control unit 902, multiple time delay lines 904, 906, 908, an electromagnetic pulse transmitter 912, two pulse wave receivers, a multichannel data acquisition unit 916, a data processing and storage unit 918, and the transmitting and receiving antennas discussed previously.
  • the clock and control unit 902 determines the sampling rate of the system To do each measurement, unit 902 sends a trigger signal via the programmable delay lines 904-908 to the transmitter 912 and the receivers 910, 914.
  • the transmitter 912 Upon the receiving of the trigger signal, the transmitter 912 generates a short electromagnetic pulse wave and emits it into space through the transmitting antenna.
  • the trigger signal also causes the receivers start sampling the reflected signals with a dynamic gam, i.e., a gain that increases with time to at least partly compensate for signal attenuation. Since the transmitter and the receivers have different response speeds, the time delay lines are carefully adjusted to guarantee synchronization between the transmitter and the receivers.
  • the receivers 910, 914 sample and output analog signals to the data acquisition unit 916, which converts the analog signals into digital signals.
  • the processing and storage unit 918 processes the received digital signals to extract measurement information.
  • 2008-IP-016303 PCT information can be stored and/or transmitted via the telemetry system to the surface for real-time monitoring.
  • Fig. 7 illustrates the operation of a time-domain electromagnetic (EM) tool that provides 3-D imaging of the borehole and the formation behind the borehole wall in the presence of non- conducting oil-based mud.
  • the tool includes an array of EM short-pulse transmitters, time- synchronized receivers, and antennas.
  • the antennas are mounted on the mandrel for LWD applications.
  • the borehole and formation reflections are processed to find out the imaging and the eccentricity of the borehole and the formation near the borehole region, which results in a 3- D imaging of the borehole and the formation near the borehole.
  • Fig. 7 shows two receiver antennas placed at different spacings with respect to the transmitter antenna to provide enough measurement equations to solve parameters for multilayer formations, and to enlarge the dynamic range of measurements.
  • the drill collar is surrounded by oil-based mud having permittivity ⁇ m and conductivity ⁇ m .
  • the standoff distance between the antennas and the borehole wall may vary with the tool-face angle in eccentric boreholes.
  • formation 1 having permittivity ⁇ i and conductivity ⁇ i
  • second formation 2 having permittivity & 2 and conductivity 0 2
  • the signals received by receiver antenna 1 include 3 components: EM waves propagating through the oil-based mud (A), EM waves propagating through formation 1 (B), and the waves reflected from the boundary between formation 1 and formation 2 (C).
  • receiver antenna 2 also receives a signal having these three components.
  • Fig. 8 shows an approximately Gaussian pulse having a pulse width T of in the range between 0.3-2.0 nanoseconds. (Some tool embodiments may support pulse widths up to 100 ns.)
  • Fig. 9 shows the simulated signal that is received in response to the transmission of the pulse in Fig. 8. In this simulation, the transmission of a pulse wave such as that shown in Fig. 8 results in the signal received by either receive antenna having the three wavelets shown in Fig. 9 (other formation configurations can produce a greater or lesser number of wavelets).
  • a ⁇ a Q + b Q ⁇ n( ⁇ + ⁇ o) (1)
  • ⁇ o an initial phase angle
  • ⁇ the tool-face angle
  • bo is determined by the eccentricity of the drilling collar. The larger the bo, the more serious the eccentricity is.
  • the antenna arrangement of Fig. 4 exploits three receivers and two transmitters to increase the number of measurement equations.
  • the two transmitters at the ends of the antenna array take turns transmitting EM pulses, and the signals from each of the three receivers are sampled in response to the transmitted pulses.
  • the use of two transmitters at two ends enables the system to determine compensated measurements that cancel system heat noise and other system errors
  • the three receivers make measurements more reliable by providing more measurement equations and making it possible to image formations with more layers.
  • the antenna arrangement of Fig. 4 also provides redundancy, enabling the system to continue operating even if one of the transmitters and one of the receivers break down.
  • the disclosed tools offer a power savings in that the high- power transmit signals have extremely short durations and a low duty cycle, creating a low average power consumption.
  • the sensors can be mounted on a rotating head to provide full azimuthal scanning at each depth in the well.
  • sensors can be mounted at different azimuthal orientations on the tool to provide "azimuthally sampled" coverage.
  • the data acquired by the 3D imaging tool can be presented in a number of forms, including a volumetric solid in cylindrical coordinates as shown in Fig. 10.
  • the volume around the borehole is divided into a cylindrical grid 1002, with each of the cells in the grid having associated formation properties, which can be shown by color, transparency, texture, and/or raa KRUEGER
  • the data acquisition system e.g., computer 50 of Fig 1
  • the user can interact with it to gam a better understanding of the structures shown, e.g , by viewing different cross-sections, different orientations, adjusting the colors, etc.
  • invasion depth and invasion rate i.e , the distance that drilling fluid has penetrated into the formation.
  • Asymmetries in the invasion rates may be indicative of stress orientations and fracture orientations, and the invasion rate can provide a measure of formation fluid mobility.
  • Another application example is the measurement of borehole caliper, shape, texture. Travel time inversion, combined with the measurement of drilling fluid properties with a so-called "mud cell”, enables accurate determination of the borehole geometry and the eccentermg of the tool. From the borehole geometry measurements, an accurate 3D model of the borehole can be constructed and displayed.
  • the tool can detect formation boundary distances and measure the variation of these distances as a function of tool face angle and tool position within the borehole. These measurements enable straightforward determination of the relative dip.
  • the antennas are enlarged and spaced further apart to support the use of low frequency electromagnetic signal pulses. Such low frequency pulses enable deeper signal penetrations into the formation. Deeper investigation depths may be possible, possibly even ahead of the bit.
  • Other applications for such tool variations include mapping of natural fractures in the formation and monitoring the growth of hydraulic fractures.
  • the processing of reflected signals need not be limited to simple time-of-flight measurements.
  • the tool can analyze reflection amplitudes, shapes, and waveform coda (signals raa KRUEGER
  • 2008-IP-016303 PCT indicative of multiple reflections or multiple scattering of the transmitted pulse) to determine formation properties, formation structural information, formation fluid properties, borehole fluid properties, borehole geometry, invasion zone geometry, and other petrophysical information that can be displayed in a 3D image either separately or combined.

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  • Physics & Mathematics (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Electromagnetism (AREA)
  • Engineering & Computer Science (AREA)
  • Environmental & Geological Engineering (AREA)
  • Geology (AREA)
  • Remote Sensing (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • General Physics & Mathematics (AREA)
  • Geophysics (AREA)
  • Geophysics And Detection Of Objects (AREA)
  • Investigating Or Analyzing Materials By The Use Of Electric Means (AREA)

Abstract

On décrit des outils et procédés de diagraphie destinés à obtenir une image tridimensionnelle (3D) de la région autour d’un trou de sonde. Dans au moins certains modes de réalisation, un outil d’imagerie 3D tourne en émettant des impulsions longues d’environ une nanoseconde et en mesurant le temps nécessaire pour recevoir des réflexions desdites impulsions. On emploie des récepteurs multiples pour donner une triangulation précise des réflecteurs. Dans certains cas, on emploie des émetteurs multiples pour obtenir des mesures compensées, c’est-à-dire des mesures où l’on compense les variations dans l’électronique des récepteurs. Comme des réflexions se produisent aux frontières entre des matériaux présentant des constantes diélectriques différentes, l’outil d’imagerie 3D peut cartographier ces frontières au voisinage du trou de sonde. Ces frontières peuvent comprendre : la paroi du trou de sonde elle-même, les frontières entre différents matériaux de la formation, des failles ou d’autres discontinuités dans une formation et des frontières entre des fluides dans une formation. En fonction de divers facteurs, la taille du voisinage du trou de sonde faisant l’objet de la cartographie peut atteindre 1 mètre.
PCT/US2009/065537 2008-11-24 2009-11-23 Imageur 3d pour trou de sonde WO2010060040A1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
US13/061,759 US9411068B2 (en) 2008-11-24 2009-11-23 3D borehole imager
GB1104663.8A GB2475456B (en) 2008-11-24 2009-11-23 A 3d borehole imager

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US11743308P 2008-11-24 2008-11-24
US61/117,433 2008-11-24

Publications (1)

Publication Number Publication Date
WO2010060040A1 true WO2010060040A1 (fr) 2010-05-27

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Family Applications (2)

Application Number Title Priority Date Filing Date
PCT/US2009/053354 WO2010059275A1 (fr) 2008-11-24 2009-08-11 Outil de mesure diélectrique à haute fréquence
PCT/US2009/065537 WO2010060040A1 (fr) 2008-11-24 2009-11-23 Imageur 3d pour trou de sonde

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PCT/US2009/053354 WO2010059275A1 (fr) 2008-11-24 2009-08-11 Outil de mesure diélectrique à haute fréquence

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US (2) US8957683B2 (fr)
EP (1) EP2361394B1 (fr)
AU (1) AU2009318042B2 (fr)
GB (1) GB2475456B (fr)
MY (1) MY160258A (fr)
WO (2) WO2010059275A1 (fr)

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US20110221443A1 (en) 2011-09-15
GB2475456B (en) 2012-11-07
WO2010059275A1 (fr) 2010-05-27
EP2361394A1 (fr) 2011-08-31
US8957683B2 (en) 2015-02-17
US20110251794A1 (en) 2011-10-13
EP2361394A4 (fr) 2015-09-02
US9411068B2 (en) 2016-08-09
GB2475456A (en) 2011-05-18
EP2361394B1 (fr) 2022-01-12
GB201104663D0 (en) 2011-05-04
MY160258A (en) 2017-02-28
AU2009318042B2 (en) 2013-11-14
AU2009318042A1 (en) 2010-05-27

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