WO2013025214A1 - Borehole acoustic noise measurement and processing - Google Patents
Borehole acoustic noise measurement and processing Download PDFInfo
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- WO2013025214A1 WO2013025214A1 PCT/US2011/048135 US2011048135W WO2013025214A1 WO 2013025214 A1 WO2013025214 A1 WO 2013025214A1 US 2011048135 W US2011048135 W US 2011048135W WO 2013025214 A1 WO2013025214 A1 WO 2013025214A1
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- WIPO (PCT)
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- acoustic noise
- noise data
- tool body
- receiver
- data
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V13/00—Manufacturing, calibrating, cleaning, or repairing instruments or devices covered by groups G01V1/00 – G01V11/00
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- 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
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- 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
- G01V1/48—Processing data
Definitions
- Measurements made in a borehole are typically performed to attain this understanding, to identify the composition, structure, properties, and distribution of material that surrounds the measurement device down hole.
- logging tools of the acoustic type are often used to provide information that is directly related to geo-mechanical properties.
- FIG. 1 is a flow chart illustrating several methods according to various embodiments of the invention.
- FIG. 2 is a block diagram of apparatus according to various embodiments of the invention.
- FIG. 3 illustrates estimated receiver gain coefficients, derived according to various embodiments of the invention.
- FIG. 4 illustrates a wireline system embodiment of the invention.
- FIG. 5 illustrates a drilling rig system embodiment of the invention.
- FIG. 6 is a flow chart illustrating several additional methods according to various embodiments of the invention.
- FIG. 7 is a block diagram of an article according to various embodiments of the invention.
- FIG. 1 is a flow chart illustrating several methods 111 according to various embodiments of the invention.
- conventional transmitters are excited at block 121 (this activity may also be skipped, since noise provided by tool movement within the borehole will be present in every case).
- recording begins at block 125.
- the tool is moved along the length of the borehole at block 129, and the received noise data generated by tool movement is recorded.
- the recording can be halted at block 133, and the acquired signal data can be stored in a buffer at block 137.
- the order of activities in blocks 125, 129, 133, and 137 can be interchanged, and individual acts can be repeated as desired.
- the acquired data can be processed, stored, and/or transmitted to the surface at block 141. If down hole processing is desired, the processed results 149 may stored and transmitted elsewhere, with or without data 149. In any case, processing may include scaling, filtering, re-sampling, and clamping (limiting).
- pulse excitation may be applied to a different conventional (active) source at block 145, and the procedure described is repeated by returning to block 121.
- the sampling rate for recording should be adjusted according to the Nyquist criterion, and is a function of the highest recorded frequency.
- Recording time is a function of the lowest record frequency.
- the listening time is usually relatively small compared to the total logging time, and each recorded sample comprises a relatively short windowed portion of the available noise.
- Tapering (using a multiplication window for the acquired signal that forces the signal magnitude near the beginning and end of the window to zero) may be used in analyzing the acquired data in the frequency domain.
- time and frequency semblance methods can be used to analyze the acquired noise data with minor modifications.
- peak detection may not be used as effectively as it is for a signal received from a traditional source (e.g., one with a separate, active transmitter).
- Time semblance methods can be applied in traditional ways, although a conventional time-slowness window (e.g., a fan, which is a two- dimensional window in time-slowness plots that reduces or eliminates noise) may be less useful in some embodiments.
- a conventional time-slowness window e.g., a fan, which is a two- dimensional window in time-slowness plots that reduces or eliminates noise
- Frequency semblance methods can also be applied in traditional ways, allowing for positive and negative slowness values simultaneously. That is, whereas conventional time semblance methods look at only positive slowness values (e.g., waves travelling from the transmitter to the receiver, and not in the reverse direction), in many embodiments positive and negative slowness values may be present. This is because noise can propagate simultaneously in the forward and backward directions (e.g., sources of noise can be located on both sides of a receiver, producing positive and negative slowness values).
- processing the negative slowness values is a straightforward extension to the existing algorithm - so this will not be described in detail here.
- Two-sided (positive and negative) frequency semblance results can be converted to one-sided results for visualization purposes by taking the absolute value of the negative slowness values.
- Time and frequency data or products from multiple recordings can be stacked (e.g., by making multiple measurements with the same acquisition arrangement, and averaging the results), as is known to those of ordinary skill in the art, to reduce or eliminate noise in the signal processing results.
- the primary source of energy used in the measurements described herein is the noise produced when the tool moves in the borehole.
- Sources that produce this noise include calipers, centralizers, and other elements forming part of the tool (including another tool in the string) that rub or scratch against the wall of the borehole.
- the movement of the tool against fluid in the borehole e.g., the sloshing noise produced by the fluid moving against the sides of the tool and the borehole
- the primary source of energy may be augmented by a secondary source of energy in some embodiments.
- additional noise may be generated by external sources, including surface operations.
- LWD logging while drilling
- MWD measurement while drilling
- the drill bit may also serve as a secondary source of energy.
- calipers, centralizers, and other parts of the tool string can be modified.
- the axial cross-section of parts of the tool can be increased to boost fluid sloshing noise.
- the pressure applied by the caliper and centralizer on the borehole wall can also be increased to amplify scratching noise.
- noise often increases with logging speed, greater logging speeds can often be used to increase noise power. As a result, noise
- characteristics can be used to measure logging speed, or to determine
- the speed of movement should change the amplitude of the noise, so that greater noise amplitude might indicate a faster logging speed.
- An abrupt increase in amplitude without a change in logging speed might indicate that a caliper has been opened, whereas an abrupt decrease in amplitude under the same conditions might indicate the caliper has been closed.
- Receivers are often manufactured with similar properties, and kept in similar conditions to better match gain properties as the components age. However, adjustments are sometimes needed when a useful match between receiver units is no longer possible. In many embodiments, acquired noise data can be used to evaluate and calibrate receiver gain.
- receiver gains are calculated, usually in a borehole or in an external enclosure - with noise operating as a relatively constant receiver matching source.
- signal amplitude or signal root-mean-square averaged amplitude in a depth range of interest can be used as a measure of signal gain.
- Receivers that have reduced gain, but are otherwise stable, can be calibrated by applying a multiplicative correction factor. Additional embodiments may be realized.
- FIG. 2 is a block diagram of apparatus 200 according to various embodiments of the invention.
- the apparatus 200 comprises a combination of one or more down hole receivers 210, and one or more processors 230. Either one of the receivers 210 and/or the processors 230 may be located inside or outside the tool body 204 (perhaps attached to the outside of the tool body 204, or not).
- the apparatus 200 may also include logic 240, perhaps comprising a programmable drive and/or sampling control system. The logic 240 can be used to acquire noise data, and other data, such as resistivity information.
- a memory 250 located inside or outside the tool body 204, can be used to store acquired noise data, and/or processing results (e.g., perhaps in a database 234).
- the memory 250 is communicatively coupled to the processor(s) 230. While not shown in FIG. 2, it should be noted that the memory 250 may be located down hole, or above the surface of the formations 266.
- some embodiments include an apparatus 200 comprising at least one receiver 210 to acquire acoustic noise data, and at least one processor 230.
- the processor 230 may operate to process the acoustic noise data to determine calibration parameters of the receivers 210, or properties of the surrounding formation 266.
- the acoustic noise data is provided by a primary, passive source of noise energy comprising a down hole tool body 204 moving within a borehole, and/or a positioning device 214 or a measurement device 218 attached to the tool body 204.
- the positioning device 214 may comprise one or more centralizers.
- the measurement device 218 may comprise one or more calipers.
- a data transmitter may be used to transmit the data and/or processing results to the surface.
- the apparatus 200 may comprise a data transmitter 244 (e.g., a telemetry transmitter) to transmit the acoustic noise data to a surface data processing system 256.
- a data transmitter 244 e.g., a telemetry transmitter
- One or more acoustic noise isolators can be attached to the tool body.
- the apparatus 200 may comprise at least one acoustic noise isolator 222 attached to the tool body 204, proximate to the receivers 210.
- the structure of the tool body may be configured symmetrically, or asymmetrically, to excite dipole modes.
- the primary, passive source of noise energy may comprise the positioning device 214 or the measurement device 218 configured as an asymmetrical device to excite resonant dipole modes.
- Three embodiments of the tool body 204 are shown in FIG. 2.
- Tool bodies 204A, 204B, and 204C illustrate different configurations of receivers 210, noise isolators 222, and separate transmitters 226 (that serve as secondary sources of energy).
- an array of receivers 210 is use to measure formation properties.
- Receivers 210 located in an axial direction along the tool body 204 can be used to make slowness measurements.
- Receivers 210 located in an azimuthal direction around the tool body 204 can be used to make azimuthally- sensitive measurements, such as a dipole measurement.
- a conventional, active transmitter 226 is used as an additional source of energy, complementing the primary and secondary sources. For example, certain modes that are not properly excited by acoustic noise can be excited by the transmitter 226.
- One or more isolator sections 222 may be attached to the tool body 204.
- the isolator sections 222 may comprise material (well known to those of ordinary skill in the art) that elongates the wave travel path to absorb tool mode energy, reducing tool modes, and thus, the resulting contamination of noise measurement.
- Multiple isolator sections 222 may be used to effectively reduce tool mode noise when the noise propagates in more than one direction.
- Noise behaves quite differently. That is, noise peaks at a relatively low frequency. Thus, noise may improve low frequency response when compared to using a traditional source, so that logging of slower formations can be conducted more effectively.
- Receiver gain estimation and calibration Some conventional processing algorithms assume all transmitters and receivers have known or identical characteristics. However under downhole conditions, acoustic transmitter and receiver characteristics may change significantly and
- Vj denotes the voltage at receiver i, taken over a number N of receivers.
- Gain is calculated with respect to the average of all receivers by computing the ratio of individual receiver gains to the average gain of all receivers.
- correction factor values ⁇ may range from about 0.97 to 1.03, and are tool -dependent. The range in values ⁇ ; could be much wider, as this factor provides compensation due to the geometry of the physical receiver location on the tool.
- the correction factor values ⁇ can be calculated by modeling and/or analytical formulas.
- the moving average filter factor/ is applied to the ratios on a logarithmic scale, before conversion back to a linear scale.
- the depth of the filter dependss on the resolution desired in the gain estimation. A window that is too long may not provide enough resolution over depth.
- a filter depth of approximately 30 meters is used.
- the deviation is calculated as a percentage, based on deviation of the ratio from a value of 1.0.
- receivers may show a 20% deviation in gain, or more.
- the baseline trend of receiver gain variation using noise as a source, compared to a conventional transmitter, is similar, although the noise result shows more variation with respect to depth.
- FIG. 3 illustrates estimated receiver gain coefficients, derived according to various embodiments of the invention.
- the graphs 310, 320, 330 illustrate frequency and time-based gain coefficients that are obtained by taking the average of each reception curve along the depth dimension (as occurs when the process described above is used), producing curves of estimated receiver gain. These are shown for the transmitter (graph 310), the noise (graph 320), and the noise as a time-based calculation (graph 330). These coefficients can be applied as described above to correct for the variations in receiver gain.
- coefficients can be applied as a dynamic gain calibration adjustment to compensate for drift as a first part of the calibration process.
- an average along the curve over a range of depths can be taken to get a single number that is used as a static calibration coefficient - which can be used prospectively, in future measurements.
- the measurements to derive gain coefficients can be made in a relatively uniform casing section, or in some selected section of a well.
- a static calibration obtained from this process can be used to log the rest of the well (e.g., the open section).
- Dynamic calibration can also be used, but sometimes produces undesirable results, because gain can be affected by local formation variations.
- the receivers can be calibrated by applying the inverse of the gain coefficients to the data. Thus, additional embodiments may be realized.
- FIG. 4 illustrates a wireline system 464 embodiment of the invention
- FIG. 5 illustrates a drilling rig system 564 embodiment of the invention
- the systems 464, 564 may comprise portions of a wireline logging tool body 470 as part of a wireline logging operation, or of a down hole tool 524 as part of a down hole drilling operation.
- FIG. 4 shows a well during wireline logging operations.
- a drilling platform 486 is equipped with a derrick 488 that supports a hoist 490.
- Drilling of oil and gas wells is commonly carried out using a string of drill pipes connected together so as to form a drilling string that is lowered through a rotary table 410 into a wellbore or borehole 412.
- a wireline logging tool body 470 such as a probe or sonde
- the wireline logging tool body 470 is lowered to the bottom of the region of interest and subsequently pulled upward at a substantially constant speed.
- the instruments e.g., the receivers 210 shown in FIG. 2
- the instruments included in the tool body 470 may be used to perform measurements on the subsurface geological formations 414 adjacent the borehole 412 (and the tool body 470).
- the measurement data can be
- the logging facility 492 may be provided with electronic equipment for various types of signal processing, which may be implemented by any one or more of the components of the apparatus 200 in FIG. 2. Similar formation evaluation data may be gathered and analyzed during drilling operations (e.g., during LWD operations, and by extension, sampling while drilling).
- the tool body 470 comprises an acoustic tool for obtaining and analyzing acoustic noise measurements from a
- the tool is suspended in the wellbore by a wireline cable 474 that connects the tool to a surface control unit (e.g., comprising a workstation 454).
- the tool may be deployed in the wellbore on coiled tubing, jointed drill pipe, hard wired drill pipe, or any other suitable deployment technique.
- a system 564 may also form a portion of a drilling rig 502 located at the surface 504 of a well 506.
- the drilling rig 502 may provide support for a drill string 508.
- the drill string 508 may operate to penetrate a rotary table 410 for drilling a borehole 412 through subsurface formations 414.
- the drill string 508 may include a Kelly 516, drill pipe 518, and a bottom hole assembly 520, perhaps located at the lower portion of the drill pipe 518.
- the bottom hole assembly 520 may include drill collars 522, a down hole tool 524, and a drill bit 526.
- the drill bit 526 may operate to create a borehole 412 by penetrating the surface 504 and subsurface formations 414.
- the down hole tool 524 may comprise any of a number of different types of tools including MWD tools, LWD tools, and others.
- the drill string 508 (perhaps including the Kelly 516, the drill pipe 518, and the bottom hole assembly 520) may be rotated by the rotary table 410.
- the bottom hole assembly 520 may also be rotated by a motor (e.g., a mud motor) that is located down hole.
- the drill collars 522 may be used to add weight to the drill bit 526.
- the drill collars 522 may also operate to stiffen the bottom hole assembly 520, allowing the bottom hole assembly 520 to transfer the added weight to the drill bit 526, and in turn, to assist the drill bit 526 in penetrating the surface 404 and subsurface formations 414.
- a mud pump 532 may pump drilling fluid (sometimes known by those of ordinary skill in the art as "drilling mud") from a mud pit 534 through a hose 536 into the drill pipe 518 and down to the drill bit 526.
- the drilling fluid can flow out from the drill bit 526 and be returned to the surface 504 through an annular area 540 between the drill pipe 518 and the sides of the borehole 412.
- the drilling fluid may then be returned to the mud pit 534, where such fluid is filtered.
- the drilling fluid can be used to cool the drill bit 526, as well as to provide lubrication for the drill bit 526 during drilling operations. Additionally, the drilling fluid may be used to remove subsurface formation 414 cuttings created by operating the drill bit 526.
- the systems 464, 564 may include a drill collar 522, a down hole tool 524, and/or a wireline logging tool body 470 to house one or more apparatus 200, similar to or identical to the apparatus 200 described above and illustrated in FIG. 2.
- housing may include any one or more of a drill collar 522, a down hole tool 524, or a wireline logging tool body 470 (all having an outer wall, to enclose or attach to instrumentation, sensors, fluid sampling devices, pressure measurement devices, transmitters, receivers, acquisition and processing logic, and data acquisition systems).
- the tool 524 may comprise a down hole tool, such as an LWD tool or MWD tool.
- the wireline tool body 470 may comprise a wireline logging tool, including a probe or sonde, for example, coupled to a logging cable 474. Many embodiments may thus be realized.
- a system 464, 564 may include a display 496 to present acoustic noise information, both measured and processed/calculated, as well as database information, perhaps in graphic form.
- a system 464, 564 may also include computation logic, perhaps as part of a surface logging facility 492, or a computer workstation 454, to receive signals from transmitters and receivers, and other instrumentation to determine properties of the formation 414.
- a system 464, 564 may comprise a down hole tool body, such as a wireline logging tool body 470 or a down hole tool 524 (e.g., an LWD or MWD tool body), and an apparatus 200 attached to the tool body, the apparatus 200 to be constructed and operated as described previously.
- a down hole tool body such as a wireline logging tool body 470 or a down hole tool 524 (e.g., an LWD or MWD tool body)
- an apparatus 200 attached to the tool body the apparatus 200 to be constructed and operated as described previously.
- the apparatus 200 tool body 204; receivers 210; positioning devices 214; measurement devices 218; separate, active transmitters 226;
- processors 230; database 234; logic 240; data transmitter 244; data processing system 256; rotary table 410; borehole 412; computer workstations 454; systems 464, 564; wireline logging tool body 470; logging cable 474; drilling platform 486; derrick 488; hoist 490; logging facility 492; display 496; drill string 508; Kelly 516; drill pipe 518; bottom hole assembly 520; drill collars 522; down hole tool 524; drill bit 526; mud pump 532; mud pit 534; and hose 536 may all be characterized as "modules" herein.
- Such modules may include hardware circuitry, and/or a processor and/or memory circuits, software program modules and objects, and/or firmware, and combinations thereof, as desired by the architect of the apparatus 200 and systems 464, 564 and as appropriate for particular implementations of various embodiments.
- such modules may be included in an apparatus and/or system operation simulation package, such as a software electrical signal simulation package, a power usage and distribution simulation package, a power/heat dissipation simulation package, and/or a combination of software and hardware used to simulate the operation of various potential embodiments.
- apparatus and systems of various embodiments can be used in applications other than for logging operations, and thus, various embodiments are not to be so limited.
- the illustrations of apparatus 200 and systems 464, 564 are intended to provide a general understanding of the structure of various embodiments, and they are not intended to serve as a complete description of all the elements and features of apparatus and systems that might make use of the structures described herein.
- Applications that may include the novel apparatus and systems of various embodiments include electronic circuitry used in high-speed computers, communication and signal processing circuitry, modems, processor modules, embedded processors, data switches, and application-specific modules.
- Such apparatus and systems may further be included as sub-components within a variety of electronic systems, such as televisions, cellular telephones, personal computers, workstations, radios, video players, vehicles, signal processing for geothermal tools and smart transducer interface node telemetry systems, among others.
- Some embodiments include a number of methods.
- FIG. 6 is a flow chart illustrating several additional methods 611 according to various embodiments of the invention.
- the methods 611 may comprise process-implemented methods, and may include, in more basic formats, acquiring acoustic noise data generated by a primary, passive source of energy, and processing the data to determine receiver calibration parameters or formation properties, or both.
- the methods 611 may begin at block 621 with acquiring acoustic noise data by at least one receiver, the acoustic noise provided by a passive source comprising a down hole tool body moving within a borehole.
- the passive source may alternatively, or in addition, comprise a positioning device or a measurement device attached to the tool body.
- the passive source down hole tool body, positioning device, or measurement device
- a drill bit or any similar device that is normally used to actively contact the surface of the formation so as to penetrate the formation and purposely increase the depth or diameter of the borehole to a substantial degree.
- active noise sources which receive power to transmit acoustic noise into the formation, such as transducers, are not included as part of the passive source.
- the acoustic noise data can be acquired from two directions at the same time.
- the activity at block 621 may comprise simultaneously acquiring the acoustic noise data from a first direction along the tool body and from a second direction along the tool body, the second direction being substantially opposite the first direction.
- Symmetrical devices can be used to excite resonant monopole modes.
- the activity at block 621 may comprise acquiring the acoustic noise data from movement of the positioning device or the measurement device configured as a symmetrical device to excite resonant monopole modes.
- Receiver gains can be calculated with, or without calibration, as described previously.
- the method 611 may continue on to block 625 to include calculating gain for one or more of the receivers without using calibration parameters.
- the calculated receiver gain can be calibrated (e.g., for gain correction after calculation) by applying static or dynamic gain correction parameters.
- Calibration factors can be applied to the receiver itself, an amplifier coupled to the receiver, or to the acoustic noise data, after acquisition.
- the method 611 may continue on to block 629 to include calibrating one or more receivers by applying static gain correction parameter (e.g., corresponding to the acoustic noise data obtained over a cased distance of the borehole), and/or dynamic gain correction parameters (e.g., corresponding to the acoustic noise data obtained over an uncased distance of the borehole, as measurements are made).
- the acoustic noise data may thus be processed at block 629 to determine calibration parameters, and perhaps apply them to one or more receivers.
- gains may be calculated using the noise source and applied to transmitter source data.
- the noise source is used to calibrate the source of the noise transmission.
- Calibration parameters (e.g., a gain coefficient or deviation in receiver gain) can also be determined by estimating the receiver gain.
- determining calibration parameters may comprise estimating the gain of the at least one receiver.
- the method 611 may continue on to block 633 to include processing the acoustic noise data to determine formation properties, to include calculating compression or shear wave slowness.
- the act of calibrating receivers at block 629 may serve to enhance the accuracy of the processing at block 633. This is especially useful in the case of dipole receivers, where two receiver poles composing the dipole can be calibrated to have similar amounts of gain.
- Processing may incorporate time/frequency semblance methods.
- the activity at block 633 may comprise applying a time semblance method or a frequency semblance method to the acoustic noise data to determine one or more formation properties.
- the acoustic noise data can be filtered to provide results with greater stability, while maintaining the desired resolution.
- the activity at block 633 may comprise applying a depth filter to the acoustic noise data after correction of the acoustic noise data for attenuation by one or more receivers.
- Some embodiments provide two-sided frequency semblance data, which can be converted to one-sided data.
- two-sided semblance data may be converted to one-sided semblance data for publication purposes, to make visualization easier.
- this activity may be obviated, since the semblance data may be received as one-sided data.
- the method 611 may continue on to block 637, to include converting two-sided frequency semblance data to one-sided frequency semblance data, perhaps using an absolute value of negative slowness values.
- the method 611 may return to block 621. If it is the case, this can be accomplished in several ways.
- devices attached to the down hole tool can be manipulated to increase the magnitude of the acoustic noise that is generated by the primary source, such as by increasing pressure between the device and the borehole wall.
- the activity at block 645 may comprise increasing azimuthal pressure applied to the borehole wall by the positioning device or the measurement device, to increase the amplitude of the measured acoustic noise data.
- logging speed can be increased to amplify acoustic noise magnitude.
- the activity at block 645 may include increasing logging speed of the down hole tool within the borehole to increase the amplitude of the acoustic noise data.
- Down hole component cross-sectional area can also be increased to amplify acoustic noise magnitude, via fluid interference, in some cases.
- the activity at block 645 may comprise increasing the cross-sectional area of the down hole tool, the positioning device, and/or the measurement device within the borehole to increase the amplitude of the acoustic noise data.
- the noise provided by the primary source may be augmented by a secondary energy source.
- a drill bit can be used to provide additional acoustic noise data. Therefore, the methods 611 may include, at block 649, augmenting the acoustic noise data with drill bit noise data during a drilling operation. The methods 611 may then return to block 621 in some
- a software program can be launched from a computer-readable medium in a computer- based system to execute the functions defined in the software program.
- One of ordinary skill in the art will further understand the various programming languages that may be employed to create one or more software programs designed to implement and perform the methods disclosed herein.
- the programs may be structured in an object-orientated format using an object-oriented language such as Java or C#.
- the programs can be structured in a procedure- orientated format using a procedural language, such as assembly or C.
- the software components may communicate using any of a number of mechanisms well known to those skilled in the art, such as application program interfaces or interprocess communication techniques, including remote procedure calls.
- the teachings of various embodiments are not limited to any particular programming language or environment. Thus, other embodiments may be realized.
- FIG. 7 is a block diagram of an article 700 of manufacture according to various embodiments, such as a computer, a memory system, a magnetic or optical disk, or some other storage device.
- the article 700 may include one or more processors 716 coupled to a machine-accessible medium such as a memory 736 (e.g., removable storage media, as well as any tangible, non-transitory memory including an electrical, optical, or
- the processors 716 may comprise one or more processors sold by Intel Corporation (e.g., Intel® CoreTM processor family), Advanced Micro Devices (e.g., AMD AthlonTM I AMD Athlon processors), and other semiconductor manufacturers.
- the article 700 may comprise one or more processors 716 coupled to a display 718 to display data processed by the processor 716 and/or a wireless transceiver 720 (e.g., a down hole telemetry transceiver) to receive and transmit data processed by the processor.
- a wireless transceiver 720 e.g., a down hole telemetry transceiver
- the memory system(s) included in the article 700 may include memory 736 comprising volatile memory (e.g., dynamic random access memory) and/or non- volatile memory.
- volatile memory e.g., dynamic random access memory
- non- volatile memory e.g., non- volatile memory.
- the memory 736 may be used to store data 740 processed by the processor 716.
- the article 700 may comprise communication apparatus 722, which may in turn include amplifiers 726 (e.g., preamplifiers or power amplifiers) and one or more antenna 724 (e.g., transmitting antennas and/or receiving antennas). Signals 742 received or transmitted by the communication apparatus 722 may be processed according to the methods described herein.
- amplifiers 726 e.g., preamplifiers or power amplifiers
- antenna 724 e.g., transmitting antennas and/or receiving antennas.
- the article 700 may comprise a down hole tool, including the tool apparatus 200 shown in FIG. 2.
- the article 700 is similar to or identical to the apparatus 200 shown in FIG. 2.
- Using the apparatus, systems, and methods disclosed herein may provide the ability to take advantage of noise measurement with only minor changes to the acquisition hardware.
- an existing acoustic system may be adapted to noise measurement in some cases by disabling transmitter firing, and modifying the data processing scheme to operate as described above.
- Passive acoustic measurements, as described herein may increase energy efficiency, provide faster logging speeds with better lateral resolution, and simplify tool design.
- Tool length may be decreased, while retaining accurate, wideband measurements.
- Receiver gain estimation and calibration may also be available. The combination of these advantages can significantly enhance the services provided by an operation/exploration company while at the same time controlling time-related costs.
- inventive subject matter may be referred to herein, individually and/or collectively, by the term "invention" merely for convenience and without intending to voluntarily limit the scope of this application to any single invention or inventive concept if more than one is in fact disclosed.
- inventive subject matter may be referred to herein, individually and/or collectively, by the term "invention" merely for convenience and without intending to voluntarily limit the scope of this application to any single invention or inventive concept if more than one is in fact disclosed.
- inventive subject matter merely for convenience and without intending to voluntarily limit the scope of this application to any single invention or inventive concept if more than one is in fact disclosed.
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Abstract
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Priority Applications (7)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
AU2011375000A AU2011375000B2 (en) | 2011-08-17 | 2011-08-17 | Borehole acoustic noise measurement and processing |
EP11870913.8A EP2745145A4 (en) | 2011-08-17 | 2011-08-17 | Borehole acoustic noise measurement and processing |
US14/237,240 US10215884B2 (en) | 2011-08-17 | 2011-08-17 | Borehole acoustic noise measurement and processing |
MX2014001847A MX2014001847A (en) | 2011-08-17 | 2011-08-17 | Borehole acoustic noise measurement and processing. |
PCT/US2011/048135 WO2013025214A1 (en) | 2011-08-17 | 2011-08-17 | Borehole acoustic noise measurement and processing |
CA2844290A CA2844290A1 (en) | 2011-08-17 | 2011-08-17 | Borehole acoustic noise measurement and processing |
BR112014003509A BR112014003509A2 (en) | 2011-08-17 | 2011-08-17 | method implemented by computer, equipment and system |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
PCT/US2011/048135 WO2013025214A1 (en) | 2011-08-17 | 2011-08-17 | Borehole acoustic noise measurement and processing |
Publications (1)
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PCT/US2011/048135 WO2013025214A1 (en) | 2011-08-17 | 2011-08-17 | Borehole acoustic noise measurement and processing |
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US (1) | US10215884B2 (en) |
EP (1) | EP2745145A4 (en) |
AU (1) | AU2011375000B2 (en) |
BR (1) | BR112014003509A2 (en) |
CA (1) | CA2844290A1 (en) |
MX (1) | MX2014001847A (en) |
WO (1) | WO2013025214A1 (en) |
Cited By (2)
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US20150338543A1 (en) * | 2014-05-23 | 2015-11-26 | Reeves Wireline Technologies Limited | Relating to geological logging |
US10215884B2 (en) | 2011-08-17 | 2019-02-26 | Halliburton Energy Services, Inc. | Borehole acoustic noise measurement and processing |
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US9612352B2 (en) * | 2012-03-30 | 2017-04-04 | Saudi Arabian Oil Company | Machines, systems, and methods for super-virtual borehole sonic interferometry |
US9766365B2 (en) * | 2014-10-27 | 2017-09-19 | Schlumberger Technology Corporation | Compensated deep measurements using a tilted antenna |
GB2553914B (en) * | 2015-03-31 | 2021-01-06 | Halliburton Energy Services Inc | Plug tracking using through-the-earth communication system |
CA2975262A1 (en) * | 2015-03-31 | 2016-10-06 | Halliburton Energy Services Inc. | Underground gps for use in plug tracking |
BR112019001495A2 (en) * | 2016-08-12 | 2019-05-07 | Halliburton Energy Services, Inc. | method for determining the properties of a pipe column of one or more pipe columns in an underground formation and system for determining the properties of a pipe column of one or more pipe columns in an underground formation |
WO2018080450A1 (en) * | 2016-10-25 | 2018-05-03 | Halliburton Energy Services, Inc. | Enhanced-resolution rock formation body wave slowness determination from borehole guided waves |
WO2018080486A1 (en) * | 2016-10-26 | 2018-05-03 | Halliburton Energy Services, Inc. | Dipole shear velocity estimation |
US11719840B2 (en) | 2018-12-28 | 2023-08-08 | Halliburton Energy Services, Inc. | Subsurface wave slowness prediction system |
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- 2011-08-17 BR BR112014003509A patent/BR112014003509A2/en not_active IP Right Cessation
- 2011-08-17 CA CA2844290A patent/CA2844290A1/en not_active Abandoned
- 2011-08-17 EP EP11870913.8A patent/EP2745145A4/en not_active Withdrawn
- 2011-08-17 MX MX2014001847A patent/MX2014001847A/en active IP Right Grant
- 2011-08-17 US US14/237,240 patent/US10215884B2/en not_active Expired - Fee Related
- 2011-08-17 AU AU2011375000A patent/AU2011375000B2/en not_active Ceased
- 2011-08-17 WO PCT/US2011/048135 patent/WO2013025214A1/en active Application Filing
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Cited By (2)
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US10215884B2 (en) | 2011-08-17 | 2019-02-26 | Halliburton Energy Services, Inc. | Borehole acoustic noise measurement and processing |
US20150338543A1 (en) * | 2014-05-23 | 2015-11-26 | Reeves Wireline Technologies Limited | Relating to geological logging |
Also Published As
Publication number | Publication date |
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EP2745145A4 (en) | 2015-11-04 |
AU2011375000B2 (en) | 2015-09-10 |
BR112014003509A2 (en) | 2017-04-18 |
EP2745145A1 (en) | 2014-06-25 |
US10215884B2 (en) | 2019-02-26 |
US20140195188A1 (en) | 2014-07-10 |
CA2844290A1 (en) | 2013-02-21 |
MX2014001847A (en) | 2014-06-05 |
AU2011375000A1 (en) | 2014-04-03 |
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