Classifications

• • 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
• • 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
• • 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
  • E21B47/0228—Determining slope or direction of the borehole, e.g. using geomagnetism using electromagnetic energy or detectors therefor
• • 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
  • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
  • E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency
• • G—PHYSICS
  • G01—MEASURING; TESTING
  • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
  • G01V11/00—Prospecting or detecting by methods combining techniques covered by two or more of main groups G01V1/00 - G01V9/00
  • G01V11/002—Details, e.g. power supply systems for logging instruments, transmitting or recording data, specially adapted for well logging, also if the prospecting method is irrelevant

Definitions

• the collection of information relating to conditions downhole, which commonly is referred to as "logging,” can be performed by several methods including wireline logging and “logging while drilling” (LWD).
• a probe or "sonde” is lowered into the borehole after some or the entire 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 direct electrical connection between the surface and the sonde provides a relatively large (but not unlimited) bandwidth for conveying logging information.
• the drilling assembly includes sensing instruments that measure various parameters as the formation is being penetrated.
• Contemplated LWD communication channels include mud pulse signaling, through-wall acoustic signaling, and electromagnetic wave signaling. In each of these channels, the useful bandwidth is highly restricted relative to wireline logging.
• Fig. 1 shows an illustrative logging while drilling (LWD) environment having an electromagnetic telemetry system
• Fig. 2 shows an illustrative volumetric data array having cylindrical coordinates
• Fig. 3 is a block diagram of an illustrative downhole tool system
• Fig. 4 is a block diagram of an illustrative surface processing system
• Fig. 5 shows an illustrative formation bed boundary in relation to a slice of the volumetric data array
• Fig. 6 shows illustrative curves of resistivity measurements versus azimuth for different radii
• Fig. 7 shows an illustrative curve of peak-to-peak variation versus radius
• Fig. 8 shows an illustrative curve of the change in peak-to-peak variation versus radius
• Fig. 9 is a flowchart of a first illustrative telemetry method that sends data from selected radii
• Fig. 10 is a flowchart of a second illustrative telemetry method that sends compressed data
• Fig. 11 is a flowchart of a third illustrative telemetry method that sends boundary distance and/or direction information.
• the issues identified in the background are at least partly addressed by the use of telemetry systems and methods designed to accommodate measurements of azimuthally sensitive tools having multiple depths of investigation.
• the volume of formation property measurements can be best represented as a cylindrical volume.
• Some system embodiments include a downhole processor coupled to a telemetry transmitter.
• the downhole processor determines a compressed representation of the formation property measurements and/or selects a subset of the measurements for transmission uphole.
• the subset selection can be based on selected radial distances having characteristics that potentially indicate features of interest to a user.
• Such features include bed boundaries, and the characteristics include sinusoidal variation as a function of azimuth, large changes in this sinusoidal variation versus radial distance, or inversion suggesting the presence of a bed boundary.
• Various compressed representations of the cylindrical data volume are disclosed, including representations based on parameters of a sinusoidal model, representations based on a two dimensional transform, and representations based on estimates of distance and direction to a bed boundary.
• FIG. 1 shows an electromagnetic telemetry system in 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. As bit 14 rotates, it creates a borehole 16 that passes through various formations.
• 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 it 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 weight and rigidity to aid the drilling process.
• drill collars include 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 types such as gyroscopes may alternatively be used.
• a downhole positioning tool 24 includes a 3 -axis fluxgate magnetometer and a 3 -axis accelerometer. As is known in the art, the combination of those two sensor systems enables the measurement of the tool face angle, inclination angle, and compass direction. In some embodiments, the tool face and hole inclination angles are calculated from the accelerometer sensor output. The magnetometer sensor outputs are used to calculate the compass direction.
• the bottom-hole assembly further includes logging instruments to gather measurements of formation properties. Using these measurements in combination with the above-mentioned tool orientation measurements, the driller can steer the drill bit 14 along a desired path using any one of various suitable directional drilling systems, including steering vanes, a "bent sub", and a rotary steerable system.
• the steering mechanism can be alternatively controlled downhole, with a downhole controller programmed to follow a chosen or dynamically-determined route.
• the bottom-hole assembly still further includes a telemetry transceiver 26 to exchange information with the surface.
• Telemetry transceiver 26 may generate acoustic signals that propagate along the walls of the drill string to a set of surface transceivers 28, with optional repeaters 30 provided to boost the signal strength.
• the surface transceivers 28 can generate acoustic signals that propagate in the opposite direction to downhole telemetry transceiver 26.
• telemetry transceiver 26 may generate EM signals 32 that propagate through the formation to a detection array 34 where it is amplified and forwarded to a data acquisition module 36 for capture and preliminary processing.
• a surface transmitter 38 can generate return EM signals 40 that propagate to the downhole telemetry transceiver 26.
• the uplink signal is provided in the form of a narrowband OFDM modulated signal.
• a data acquisition module 36 receives the uplink signal from the EM detection array 34 and/or surface transceivers 28. Module 36 optionally provides some preliminary processing (e.g., beam-forming to enhance signal to noise ratio) and digitizes the signal.
• a data processing system 50 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
• a user interacts with system 50 and its software 52 via one or more input devices 54 and one or more output devices 56.
• a number of LWD tools may be included in the bottom hole assembly, such as
• ADR Azimuthal Deep Resistivity
• the ADR tool is an induction tool that makes attenuation and phase shift for multiple depths of investigation in each of multiple azimuthal sectors.
• Multiple transmitter-receiver antenna spacings are employed to provide multiple depths of investigation. Though each antenna spacing corresponds to a different depth of investigation (DOI), these DOIs typically vary with formation resistivity.
• DOI depth of investigation
• the measurements for fixed DOIs can be calculated from the measurements obtained using the various antenna spacings. Such processing is not required, but it is well within the capabilities of the downhole processor.
• Displacement along the borehole axis is represented by the Z-axis
• radial displacement R is usually measured perpendicular to the borehole axis
• azimuth ⁇ is usually measured angularly from the top side of the borehole (for approximately vertical boreholes, the azimuth is measured angularly from the north side of the borehole).
• the ADR tool makes attenuation and phase shift measurements of electromagnetic waves at 10 depths of investigation in each of about 32 azimuthal sectors. Without some form of compression or selectivity, the amount of data from this tool alone will quickly overwhelm most LWD telemetry schemes. Nevertheless, it is desirable to have such information available in real time at the surface for geosteering, formation characterization, and formation visualization/mapping. Accordingly, a number of transmission techniques are disclosed herein, exploiting various features of the data geometry for compression and/or selective data transmission.
• Fig. 3 is a block diagram of an illustrative downhole tool system having a control module 302, a power module 304, an optional storage module 306, and one or more sensor modules 308- 310.
• a tool bus 312 enables the control module 302 to communicate with each of the other modules 304-310 to transfer data and control their operations.
• a telemetry module 314 couples top the control module 302 to enable the control module to communicate with a data processing system 50 (Fig. 1) at the surface to exchange data and to receive commands for configuring the operation of the bottom hole tool assembly.
• Power module 304 supplies power to the other modules. To that end, the power module
• Optional storage module 306 includes memory for storing logging measurement data until it can be transmitted to the surface or until the tool is recovered and the data can be directly downloaded.
• Sensor modules 308-310 represent tools (such as the ADR tool) for measuring formation characteristics and tools for measuring parameters of the drilling operation including tool position and orientation.
• Control module 302 configures the operation of the sensor modules and coordinates the transfer of tool measurement data from the sensor modules to the storage module. As previously mentioned, the volume of stored data can grow too quickly to allow for all the information to be telemetered to the surface. Accordingly, control module 302 sends data to the surface in accordance with a subset selection and/or compression method described herein below. Telemetry module 314 communicates data to the surface using any suitable LWD telemetry technique including mud pulse telemetry, acoustic telemetry, and electromagnetic telemetry.
• Fig. 4 is a block diagram of an illustrative surface processing system suitable for collecting volumetric logging data and generating visualizations thereof.
• a user may further interact with the system to send command to the bottom hole assembly to adjust its operation in response to the received data.
• the system of Fig. 4 can take the form of a computer that includes a chassis 50, a display 56, and one or more input devices 54, 55.
• Located in the chassis 50 is a display interface 402, a peripheral interface 404, a bus 406, a processor 408, a memory 410, an information storage device 412, and a network interface 414.
• Bus 406 interconnects the various elements of the computer and transports their communications.
• the surface telemetry transducers are coupled to the processing system via the network interface 414 to enable the system to communicate with the bottom hole assembly.
• the processor processes the received telemetry information received via network interface 414 to reconstruct a volumetric logging data set and display it to the user.
• the processor 408, and hence the system as a whole generally operates in accordance with one or more programs stored on an information storage medium (e.g., in information storage device 412).
• the bottom hole assembly control module 302 operates in accordance with one or more programs stored in an internal memory.
• Fig. 5 shows a "constant Z" slice 502 of the illustrative cylindrical data volume.
• the dimensions of the data cells need not be uniform, and in the illustrate example the outer rings have larger radial extents.
• Fig. 5 further shows an illustrative boundary 504 between two formation beds 506 and
• Ring 510 marks the approximate region where the tool measurements begin indicating the presence of the boundary.
• Fig. 6 shows illustrative graphs of the tool's measurements of resistivity versus azimuth.
• the curves 601-606 indicate that within the inner rings of the tool's measurement range, the measured phase shifts and attenuation indicate a relative constant resistivity.
• the curve for the seventh ring 510 (curve 607) is intermediate between the curves for the inner rings and the curves for the outer rings. The radial distance of this transition ring is indicative of the distance to the bed boundary.
• Curves 608-610 indicate that the attenuation and phase shift measurements for the outer rings (those that are traversed by the bed boundary 504) indicate a sinusoidal variation of the resistivity.
• Fig. 7 shows the sinusoidal peak-to-peak magnitude of curves 601-610 as a function of radial distance.
• the peak-to-peak oscillation amplitude can be determined by either fitting a curve or simply calculating a maximum difference between opposite azimuthal orientations.
• the peak-to-peak amplitude can be determined using a transform such as a discrete cosine transform.
• a predetermined or dynamically determined threshold value 702 may be used to determine which, if any, of the rings of data should be communicated to the surface.
• Fig. 7 shows that the seventh ring has the first peak-to-peak value 704 to exceed the threshold.
• Fig. 8 shows a derivative of the peak-to-peak magnitude curve of Fig. 7.
• a predetermined or dynamically determined derivative threshold 802 may be used to determine which, if any, of the rings of data should be communicated to the surface.
• Fig. 8 shows that the seventh and eighth rings have derivative values 804, 806 that exceed the derivative threshold 802. The use of these criteria and others is described below.
• Fig. 9 is a flowchart of a first illustrative telemetry method that sends data from selected radii. In block 902, the control module determines the current tool position and/or orientation.
• control module tracks only time information, which can be later mapped to a tool position using position data collected at the surface.
• the control module collects and stores the formation data as a function of azimuth (aka tool face angle) and radius (aka depth of investigation). Note that the sensor module may be able to repeat its measurements many times at each azimuth and depth of investigation and statistically combine the measurements to improve measurement accuracy.
• the control module processes the data to select one or more radii of interest.
• the radius of interest is determined to be that of the innermost ring having a peak-to-peak magnitude above a threshold (e.g., threshold 702 in Fig. 7).
• the radii of interest are those of the one or more rings (if any) having changes in peak-to-peak magnitude above a threshold (e.g., threshold 802 in Fig. 8).
• the radius of the maximum derivative is chosen (point 806 in Fig. 8).
• the radii of interest are those of the rings having the minimum and maximum peak-to-peak variations.
• the control module processes the data to determine a distance to a bed boundary and the radii of interest are chosen for the rings that bracket this distance.
• control module selects a subset of the formation data to send to the surface based on the identified radii of interest.
• the selected formation data is preferably the data from the rings having the radii of interest, optionally including the adjacent inner and outer rings.
• control module selects an arbitrary ring or sends an average resistivity value for the whole slice. The process then repeats, starting again with block 902.
• Fig. 10 is a flowchart of a second illustrative telemetry method that sends compressed data.
• the control module determines the tool position and collects formation data in blocks 902 and 904.
• the control module extracts, from each "constant-Z" slice of formation data, various characteristic parameters that provide a condensed representation of the formation data.
• these parameters include (optionally for each of attenuation and phase shift) an average for the slice, a maximum (or minimum) sinusoidal peak- to-peak variation, the azimuthal direction of the peak variation, and a sequence of peak-to-peak delta values indicating the change in peak-to-peak variation from one ring to the next.
• these parameters are sent to the surface and the process repeats from block 902.
• the parameter values can be each expressed as a change in value with respect to the parameters of the previous slice.
• the control module calculates a difference between the average value for this slice and the average for the preceding slice. Once this difference has been communicated to the surface, the processing system adds the difference to the average from the preceding slice to obtain the average for this slice.
• the control module may only send the position and magnitude of the largest one or two peak-to-peak delta values, or only the position and magnitude of those delta values having magnitudes above a threshold.
• the control module can optionally send deviations from the idealized model represented by the foregoing parameters. For example, given the foregoing parameters, the processing system can predict the measurements for each bin in the cylindrical data volume. The control module can encode and send some or all of the differences between this prediction and the actual measurement values. Thus, the position and values of the largest differences can be encoded and sent to refine the model reconstructed by the processing system at the surface.
• Fig. 11 is a flowchart of a third illustrative telemetry method that sends boundary distance and/or direction information. As in Fig. 9, the control module determines the tool position and collects formation data in blocks 902 and 904.
• the control module processes the formation data to determine the desired information about the information, e.g., resistivity and resistive anisotropy of the current formation bed, as well as the distance and direction to the nearest bed boundary.
• desired information e.g., resistivity and resistive anisotropy of the current formation bed
• Methods for determining this information are known and can be readily implemented by a downhole processor. See, e.g., U.S. Pat. 6,476,609 entitled “Electromagnetic wave resistivity tool having a tilted antenna for geosteering within a desired payzone” by Michael Bittar, or application PCT/US07/64221 entitled “Robust inversion systems and methods for azimuthally sensitive resistivity logging tools" by Michael Bittar and Guoyu Hu.
• multiple boundaries can be identified and tracked to enable distance/direction information to be determined for each boundary.
• the control module transmits the desired formation information to the surface and the process repeats beginning in block 902.
• the extracted formation information is further processed to generate a predicted tool response that is subtracted from the tool measurements. This subtraction is expected to greatly reduce the dynamic range of the data, enabling the data to be represented with significantly fewer bits. If sufficient bandwidth is available, all of these differences can be transmitted to the processing system at the surface to enable full reconstruction of the measured data. Alternatively only a selected group of differences may be transmitted to enable a more approximate reconstruction of the data. Suitable selection methods include reduced spatial resolution (e.g., sending differences from every-other azimuthal sector and every-other ring), and selecting based on magnitude of the differences (e.g., sending only those differences that exceed some threshold).
• control module processes the formation data downhole to determine the boundary distance and direction information.
• the control module operates as an autopilot to automatically steer the drilling assembly in response to this boundary information, maintaining the borehole at a programmed distance from the boundary.
• the foregoing methods also enable real-time updating of an "earth model", e.g., a representation of the geology in a surrounding region.
• a model is useful in characterizing and exploiting hydrocarbon reservoirs.
• the representation can take the form of a data volume having rectilinear bins, or 'voxels', containing one or more formation property values such as density, porosity, slowness, resistivity, and so on.
• the representation can take the form of labeled geological strata that are characterized by approximate position, orientation, and shape, as well as one or more characteristics that enable the strata to be distinguished from one another. Other representations can also be used.
• Such an earth model can be developed from seismic surveys, exploratory wells, and geological studies of the region.
• the foregoing methods enable knowledge of the tool position to be combined with measurements of boundary distance and direction for a relatively precise determination of boundaries between strata.
• the earth model parameters can then be adjusted to enforce agreement with the tool measurements.
• the precise adjustment method depends on the form of the earth model. For example, if the representation takes the form of labeled strata, the orientation and thickness of the strata can be adjusted to match the tool measurements.
• every sixteenth slice can be compressed using a two- dimensional discrete cosine transform (2D-DCT) technique similar to JPEG compression, but in the cylindrical coordinate system.
• 2D-DCT discrete cosine transform
• the coefficients are scaled, quantized, re-ordered, run-length encoded, and variable-length (e.g., Huffman) coded to significantly reduce the number of bits needed to represent the slice data.
• the intermediate slices are differentially encoded relative to the preceding slice, leading to even greater reduction in the number of bits needed to represent these slices. This adaptation of the JPEG technique is expected to be particularly effective due to the cylindrical geometry of the measurement data.
• bandwidth-saving techniques disclosed herein are also applicable to other azimuthally-sensitive logging tools and to the wireline environment. It is intended that the following claims be interpreted to embrace all such variations and modifications.

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• 2008
  • 2008-11-19 US US12/808,193 patent/US10222507B2/en active Active
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