• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
  • 同族专利
  • 引用文献
  • 法律状态
  • 优先权
    • 专利摘要:
    DRILLING DRILL WITH PENETRATION SENSOR RATE. The present invention relates to an apparatus for estimating the penetration rate of a drill bit, which in one embodiment includes a first sensor positioned on a drill bit, configured to provide a first measurement of a parameter in a selected location in the formation in a first time, and a second sensor positioned spaced at a selected distance from the first sensor to provide a second measurement of the parameter at the selected location, a second time when the drill bit crosses the bottom of the well. The device can also include a processor configured to estimate the penetration rate, using the selected distance and the first and second time.
    公开号:BR112012005535B1
    申请号:R112012005535-6
    申请日:2010-09-09
    公开日:2021-02-09
    发明作者:Sorin G. Teodorescu
    申请人:Baker Hughes Incorporated；
    IPC主号:
    专利说明:

    CROSS REFERENCE
    [0001] This application claims priority to U.S. Non-Provisional Patent Application Serial Number 12 / 557,004, entitled DRILL DRILL WITH PENETRATION SENSOR RATE, filed on September 10, 2009. BACKGROUND INFORMATION Description field
    [0002] This description refers in general to drill bits including sensors to provide measurements for a property of interest to a formation and systems using such drill bits. Brief Description of the Related Art
    [0003] Oil wells (wells or boreholes) are drilled with a drill string that includes a tubular member having a drill set (also referred to as the downhole assembly or "BHA") that has a drill bit attached to the lower end of the BHA. The drill bit is rotated to disintegrate soil formations in order to drill the well. The BHA typically includes devices to provide information about the parameters relating to the behavior of the BHA, parameters of the formation involving the well and parameters related to drilling operations. One such parameter is the penetration rate (ROP) of the drill bit in the formation.
    [0004] A high ROP is desirable because it reduces the total time required for drilling a well. The ROP depends on several factors including the drill bit design, rotation speed (or revolutions per minute or RPM) of the drill bit, type of weight drilling fluid over the bit being circulated through the well and the rock formation. A low ROP typically extends the life of the drill bit and BHA. Drilling operators try to control ROP and other drilling and drill string parameters to obtain a combination of parameters that will provide the most effective drilling environment. ROP is typically determined based on devices arranged on the BHA and on the surface. Such determinations often differ from the actual ROP. In this way, it is desirable to provide an improved device for determining or estimating ROP. SUMMARY
    [0005] In one aspect, a drill bit that is described in one embodiment can include a first sensor positioned on the drill bit, configured to provide a first measurement of a parameter at a selected location in a formation at a first time, and a second sensor positioned at a selected distance from the first sensor to provide a second measurement of the parameter at the selected location a second time, when the drill bit crosses the bottom of the well. The drill bit can also include a processor configured to estimate the penetration rate using the selected distance and the first and second times.
    [0006] In another aspect, a method for estimating a penetration rate of a drill bit in a well is provided, in which a modality may include: the identification of a selected feature in a selected location of a formation surrounding a well, a first time, using measurements from a first sensor on the drill bit; identify the selected feature at the selected location a second time, using measurements from a second sensor on the drill bit; and estimate the penetration rate for the drill bit based on a distance between the first sensor and the second sensor, the first time and the second time.
    [0007] Examples of certain characteristics of a drill bit having a displacement sensor are summarized somewhat more broadly, so that the detailed description of them below can be better understood. There are, of course, additional features of the drill and drilling systems, to use the same as described hereinafter, which form the subject of the attached claims. BRIEF DESCRIPTION OF THE DRAWINGS
    [0008] For a detailed understanding of the present description, references should be made to the following detailed description, taken in conjunction with the accompanying drawings, in which similar elements have in general been designated with similar numerals and where: figure 1 is a schematic diagram of an exemplary drilling system that includes a drill string having a drill bit and sensors according to one embodiment of the description; figure 2 is an isometric view of an exemplary drill bit showing the location of the sensors in the drill bit and an electrical circuit that can process the signals from the sensors, according to one embodiment of the description; figure 3 is an isometric view of a portion of the exemplary drilling machine shown in figure 2, illustrating hidden lines to show certain internal portions of the drill bit stem and pin sections and the placement of the sensors, measurement circuit and hardware on that local, according to a description mode; figure 4 is a side sectional view of a portion of the pin of the exemplary drill bit, showing internal portions of the pin portion, a controller and other measuring equipment in the drill bit, according to an embodiment of the description; and Figure 5 is a schematic view of an exemplary measurement system that can be used to determine the ROP of a drill bit, according to an embodiment of the description. DETAILED DESCRIPTION
    [0009] Figure 1 is a schematic diagram of an exemplary drilling system 100 that can use drill bits and monitoring systems described here for drilling wells. Figure 1 shows a well 110 that includes an upper section 111 with a housing 112 installed there, and a lower section 114 being drilled with a drill column 118. Drill column 118 is shown to include a tubular member 116 carrying the BHA 130 at its lower end. Tubular member 116 can be formed by joining tube sections or it can be composed of a flexible tube. Drill bit 150 is coupled to the lower end of BHA 130 to disintegrate rocks in the formation of the soil to drill well 110.
    [00010] Drill column 118 is displayed transported in well 110 from a probe 180 on surface 167. The probe 180 shown is a land-based probe to facilitate explanation. The devices and methods described here can also be used when using a marine probe (not shown). A rotary table 169 or a top drive system (not shown) coupled to the drill column 118 can be used to rotate the drill column 118 on the surface, which rotates the BHA and thus the drill bit 150 to drill the well 110. A drill motor 155 (also referred to as a "bottom motor") in the drill assembly can be used alone to rotate the drill bit 150 or to override the drill bit rotation by the rotary table 169. A control unit (or "controller") 190, which can be a computer-based unit, can be placed on the surface to receive and process the data transmitted by the sensors on the drill bit and BHA 130 and to control the selected operations of the various devices and sensors in BHA 130. The surface controller 190, in one embodiment, may include a processor 192, a data storage device (or "computer-readable medium") 194 for storage data and computer programs 196. The data storage device 194 can be any suitable device, including, but not limited to, read-only memory (ROM), random access memory (RAM), instant memory, magnetic tape , hard disk and an optical disk. During drilling, a drilling fluid from a source of the same 179 is pumped under pressure through the tubular member 116, the fluid of which is discharged at the bottom of the drill bit 150 and returns to the surface through the annular space 127 (also referred to as the " annular space ") between the drilling column 118 and the inner wall of the well 110.
    [00011] Still referring to figure 1, the drill bit 150, in one embodiment, can include sensors 160 and 162, circuits for processing signals from such sensors and for estimating one or more parameters related to drill bit 150 or to the drilling column when drilling well 110, as described in more detail with reference to FIGS. 2 and 3. In one aspect, sensors 160 and 162 can be located on a drill body, such as a shank, configured to determine the penetration rate (ROP) of the drill bit 150. BHA 190 can additionally include a or more downhole sensors (also referred to as measurement sensors during drilling (MWD)), collectively designated here by the numeral 175, and at least one control unit (or controller) 170 for processing the data received by the MWD sensors 175, sensors 160 and 162, and other sensors in drill bit 150. Controller 170 may include processor 172, such as a microprocessor, data storage device 174 and programs 176 for use by processor 172 to process downhole data and to communicate with the surface controller 190 through a bidirectional telemetry unit 188.
    [00012] In one aspect, a controller 370 can be positioned on the drill bit 150 to process the signals from sensors 160 and 162 and other sensors on the drill bit. As discussed in detail with reference to FIGS. 2-5, controller 370 can be configured to be placed on the drill bit at a surface pressure close to sensors 160 and 162. Such a configuration is desirable as it can reduce signal degradation and enable the controller to process sensor signals faster, compared to the processing of sensor signals by a controller in the BHA, such as controller 170. Controller 370 may include a processor 372, such as a microprocessor, a data storage device 374 and programs 376 for use by processor 372, to process downhole data and to communicate with controller 170 at BHA and surface controller 190.
    [00013] Figure 2 shows an isometric view of an exemplary PDC drill bit 200, made according to one embodiment of the description. In one configuration, drill bit 200 may include sensors 260 and 262 to obtain measurements related to the ROP of drill bit 200 and certain circuits to process at least partially the signals generated by such sensors. A PDC drill bit is displayed for explanation purposes only. Any type of drill bit, including, but not limited to, triconic drill and diamond drill, can be used for the purpose of this description. Drill bit 200 is shown to include a drill body 212 comprising a crown 212a and a stem 212b. Crown 212a is displayed to include a number of blade profiles (or profiles) 214a, 214b ... 214n. All profiles (214a, 214b.. 214n) end close to the bottom center 215 of drill bit 200. Several cutters are shown placed along each profile. For example, profile 214a is displayed to contain cutters 216a-216m. Each cutter has a cutting element, such as element 216a 'corresponding to cutter 216a. Each cutting element comes into contact with the rock formation when the drill bit is rotated to drill the well. Each cutter has an angle of attack and a side angle that defines the cut made by that cutter in the formation.
    [00014] Still with reference to figure 2, in one embodiment, sensors 260 and 262 can be placed in the recessed portion 230 of stem 212b. The sensors 260 and 262 are spaced and selected at a distance of 264 from each other, along a longitudinal axis 240 of the drill bit 200, enabling each sensor to make measurements at different locations (or depths) in the well. Sensors 260 and 262 can be located in any suitable position on drill bit 200, such as on drill body 212 or drill stem 212b. In one aspect, sensors 260 and 262 can protrude from or be coupled to the surface of the drill bit body, thereby enabling sensors 260 and 262 to transmit and receive signals from a wall of the formation. In another embodiment, the sensors can be placed inside the drill bit 200. In each case the sensors are positioned and configured to transmit the signals through the fluid in the well, for formation, and to receive formation signals in response to the transmitted signals.
    [00015] In one aspect, sensors 260 and 262 can be acoustic sensors using acoustic signals and / or energy to measure geophysical parameters (for example, acoustic speed and acoustic path time). In addition, sensors 260 and 262 can also detect reflected acoustic waves to identify specific discontinuities in the formation or an acoustic image of the well wall. Illustrative acoustic sensors include acoustic wave sensors that use piezoelectric material, magnetostrictive materials, etc. In addition, each sensor can be a transducer (combination of transmitter and acoustic receiver). The transmitter can transmit acoustic signals, such as a high frequency signal, at a selected depth of the well and the receiver receives the acoustic waves reflected from the well wall and thus recognizes the discontinuities in the formation at substantially the same depth. In other modalities, sensors 260 and 262 can measure other parameters, such as resistivity and gamma rays. In another aspect, trackers (magnetic or chemical) can be used to determine ROP. The signals from sensors 260 and 262 can be provided via conductors 240 to a circuit 250 located outside the drill bit or placed in drill bit 212b. In one aspect, circuit 250 can be configured to amplify the signals received from sensors 260 and 262, digitize the amplified signals and transmit the digitized signals to controller 370 on drill bit 200 (figure 3), controller 170 on BHA and / or surface controller 190 for further processing. One or more of such controllers process the sensor data and estimate the instantaneous ROP of the sensor signals using programs and instructions provided to such controllers, as described in greater detail with reference to figures 3 and 4.
    [00016] Figure 3 is an isometric view of shank 212 and pin section 312 of drill bit 200 shown in figure 2, describing the hidden lines to show certain internal portions of shank 212b and pin section 312 of drill bit 200 , and the placement of certain sensors, measurement circuit and other equipment, according to a modality of the description. Shank 212b and pin section 312 include an orifice 310 for supplying drilling fluid therethrough to drill ring 212a 200 (figure 2) and one or more longitudinal sections surrounding orifice 310, such as sections 313, 314 and 316 The section 314 includes a recessed portion 230. Additionally, the upper end of the rod section of the pin 312 includes a recessed area 318. A suitable coupling mechanism, such as the fillets 319 in the pin section 312 (or neck) connects the drill bit 200 to the drill set 130 (figure 1). On the sides, sensors 260 and 262 can be placed in any suitable location, including in the recessed portion 230, in the region of pin 364, within 336 in the drill bit or in any other location. In the particular embodiment of figure 3, sensors 260 and 262 are displayed positioned in recess 314 and separated by a distance 264 along the longitudinal direction of the drill bit 200. Conductors 242 and 334 can be operated from sensors 260 and 262 at a electrical circuit 349 in recess 318 through suitable conductors 242 in recess 334 in rod 212 and pin section 312. In one aspect, circuit 349 may include a circuit for signal conditioning, such as an amplifier that amplifies the signals from sensors 260 and 262 and an analog-to-digital converter (AID) that digitizes the amplified signals. The digitized signals are provided to a controller 370 for processing. In one aspect the controller 370 may include a processor 372, a data storage device 374 and programs 376 for use by processor 372 to process the signals from sensors 260 and 262. In another aspect, sensors 260 and 262 may be located at the along another section of the rod or pin section, as shown by elements 336a and 336b, or in any other suitable location. In another configuration, the sensors can be positioned on an external surface of the rod 212b, in the drill body 212, in the pin section 312 or other portions of the drill, and the signal conditioning and digitizing elements can be positioned on the rod 212b. If the sensor elements are recessed in the stem 212b or drill body 212, then a window formed by a means that does not block the signals used for measurement, such as acoustic waves, electromagnetic waves and gamma radiation, can be interposed between the element sensor and stem surface 212b or drill body 212. In another configuration, signals from sensors 260 and 262 can be processed by a circuit 250 (figure 2) outside of drill bit 200. Circuit 250 can be the controller 170 in the BHA or the controller 190 (figure 1) on the surface or a combination thereof. Drill bit 200 signals can be communicated to external circuit 250 by any suitable method, including, but not limited to, electrical coupling and acoustic transmission.
    [00017] In one embodiment, sensors 260 and 262 can be acoustic sensors configured to transmit acoustic waves at selected frequencies to the formation involving the drill bit 200 and to receive acoustic waves from the formation in response to the transmitted waves. The acoustic sensors (260, 262) can transmit acoustic waves on the wall of the well 354 at a frequency, where the wall 354 will cause the waves to reflect back to the sensors (260, 262). The sensors 260 and 262 can receive the reflected waves and the controller 370, 190 and / or 170 determines a characteristic of the well wall from the reflected signals. In operation (ie, while drilling), the acoustic sensor 262 transmits a signal at a time T1 at depth 356 and the processor (370, 170 and / or 190) determines a specific characteristic (such as an image of the well wall or training) from the signals received. As the drill bit moves towards the bottom of the well 360, the sensor 260 continuously transmits signals at the same frequency as the sensor 262 and receives the acoustic signals that are processed by the processors. When the drill bit traveled distance 264 at time T2, processors may be able to match the characteristic determined using sensors 262 and 260. Therefore, the controller and processor can calculate a ROP for the drill bit from the elapsed time (T2-T1) and the known distance 264. For example, if the elapsed time (T2-T1) is 20 seconds and the distance (264) is six inches, the ROP (distance over time: six inches / 20 seconds) ) will be 0.3 inches / second. In other embodiments, as discussed below, the devices can use the technique described above with any suitable sensors, such as gamma ray sensors, resistivity sensors, and sensors that detect injected chemicals, magnetic or nuclear trackers.
    [00018] In another embodiment, sensors 260, 262 can use a gamma ray measurement to calculate the ROP for the drill bit. The sensors 260, 262 can be configured to use gamma ray spectroscopy to determine the amounts of concentrations of potassium, uranium and thorium that occur naturally in geological formation. Measurements of gamma radiation from these elements can be used because these elements are associated with radioactive isotopes that emit gamma radiation at characteristic energies. The amount of each element present within the formation can be determined by its contribution to the flow of gamma rays in a given energy. The measurement of gamma radiation of these concentrations of specific elements is known as spectral removal. Spectral removal refers to subtracting the contribution of unwanted elements within an energy window, including upper and lower limits, established to encompass the characteristic energy (s) of the desired element within the energy spectrum of gamma rays. . Because of these factors, spectral removal can be performed by calibrating the tool initially in an artificial formation with known concentrations of potassium, uranium and thorium under standard conditions.
    [00019] Illustrative devices for detecting or measuring naturally occurring gamma radiation include magnetic spectrometers, scintillation spectrometers, proportional gas meters and semiconductors with solid state meters. For example, a suitable gamma ray sensor can use a sensor element that includes a scintillation crystal and an optically coupled photomultiplier valve. The output signals from the photomultiplier valve can be transmitted to a suitable electronic package that can include pre-amplification and amplification circuits. The amplified signals from the sensors can be transmitted to the processor in a controller. In certain embodiments of the description, solid-state devices for the detection of gamma rays can be used.
    [00020] Gamma ray sensors configured to detect naturally occurring gamma ray sources can provide an indication of a lithology or change of lithology in the vicinity of drill 200. With reference to figure 3, sensors 260 and 262 can be sensors of gamma. In modalities, at time T1 the signals from gamma ray sensors 260 and 262 can be used to estimate an energy signature for locations 358 and 356, respectively, within the formation being drilled. Thereafter, at time T2, the energy signature detected for location 356 can be detected by sensor 260. The elapsed time (T2-T1) between signature measurements and distance 264 can be correlated and processed to determine the ROP for the drill bit.
    [00021] In yet another configuration, sensors 260 and 262 can be resistivity sensors that provide an image or map of the structural characteristics of the formation. The image of locations selected with sensor 262 at time T1 and the same image determined by sensor 260 at time T2, taking the known separation distance 264, can be used to determine the ROP of the drill bit, as described above with respect to acoustic signals.
    [00022] Figure 4 is a schematic view of a modality of a ROP 400 measurement system. A portion of the 400 system is located on the drill stem 402, where sensors 404 and 406 are chemical tracking sensors. The chemical tracking sensors (404, 406) use chemical signatures to identify locations on the wall of well 408. For example, the tracking sensor 404 can emit a charge of chemicals 410 that reaches a location 409 on the wall of formation 408 In one aspect, the chemical load 410 creates a chemical signature in the formation at site 409 at time T1. As the drill traverses downhole 411, sensor 406 can detect the signature of chemicals at location 409 at time T2. Thus, a controller 415 can calculate a ROP based on the elapsed time, T2-T1, and a distance 412 between sensors 404 and 406. The chemical tracking sensors 404, 406 can be supplied to the chemicals by a pump 414, lines Fluid Transmission 416 and Storage Containers 418. Controller 415, Pump 414, Fluid Transmission Lines 416 and Storage Containers 418 can be located on the surface, in the drill string or on the drill bit, depending on the application. In the modalities discussed, both sensors can be placed in areas of the rod, pin, cone or crown. In other embodiments, the sensors may be in different locations, for example, one on the stem and one in the area of the crown, pin, or cone. The important factor in determining the ROP is that the distance between the sensors is known and the time between measurements at a selected location is accurately measured.
    [00023] Figure 5 shows a modality of a portion of the neck section 500 that can be used to house the electronic circuits 370 (figure 3) at low pressure. The neck section 500 can be the portion of the drill bit opposite the crown or cone section (containing the cutters) and can be coupled to the portion of the drill column through fillets, located on surface 530, or other suitable coupling means . The neck portion 500 may include an internal orifice 510, a generally circular piece 512 and an area in recess 515. The inner orifice 510 may enable the communication of drilling fluid, production fluid and the routing of various electrical transmission lines, communication and fluids through the drill bit. In one aspect, the recessed area 515 can receive a sealing member 514 that is configured to accommodate depressurized components, such as electronic components. The sealing member 514 can display a large flange 516 and a small flange 518 at opposite ends of a cylindrical portion 520. The cylindrical portion 520 can have an open circular volume or cavity area 522 that can accommodate components that are protected from increased pressure in which the drill and BHA are described rock bottom.
    [00024] In one aspect, the sealing member 514 and the sealing member cavities are sealed from the external pressure by the seals 524 and 526 between the sealing member 514 and the circular part 512. The seals 524 and 526 can be any mechanisms suitable sealing rings, such as a sealing ring made of rubber, silicone, plastic or other durable composite sealing material. Seals 524 and 526 can be configured to seal sealing member 514 up to 20,000 pounds per square inch (psi) of downhole pressure outside the drill bit. Due to the configuration of the sealing member 514 and the seals 524 and 526, the electronic components are protected within the depressurized environment within the sealed area. For example, a controller 570 can be positioned within the sealed portion of the sealing member 514 to process the signals from the sensors used to calculate the ROP. Controller 570 may include processor 572, data storage device 574 and programs 576 for use by processor 572 to process downhole data and to communicate with surface controller 190 (figure 1). Other circuits 580, such as signal conditioning and communication equipment, can also be located within the sealed portion of the sealing member 514. Controller 570 can communicate with the surface and other portions of the drill string via insulated conductor wires ( copper wires), fiber optic cables, wireless communication or another suitable telemetric communication technique. Wires, cables, drilling fluid and / or forming fluid can be routed through a cavity 528 in the sealing member to the drill string. In one aspect, the sealing member 514 and the components within the sealing member enable the processing and communication of signals and measurement data, such as signals from the acoustic sensors (260, 262 of figures 2, 3), thereby providing a measurement of the ROP for the drill bit inside the well.
    [00025] The foregoing description is addressed to certain modalities for purposes of illustration and explanation. It will become evident, however, for people versed in the technique that many modifications and changes to the modalities advanced above can be made without departing from the scope and spirit of the concepts and modalities exposed here. It is intended that the following claims should be interpreted as encompassing such modifications and changes.
    权利要求:
    Claims (9)
    [0001]
    1. An apparatus for use in drilling a well hole (110), comprising: a first sensor (260) positioned on a drill bit (200) positioned on the drill bit (200) configured to provide a first measurement of a parameter in a selected location in the formation (358) in a first time; a second sensor (262) positioned spaced at a selected distance from the first sensor (260) to provide a second measurement of the parameter at the selected location (356) a second time when the drill bit (200) crosses the downhole; and the apparatus characterized in that the drill bit (200) comprises a recessed area (515) that receives a sealing member (514) and is configured to be at a surface pressure, in which a controller (370) including the processor (572) is housed in the recessed area (515).
    [0002]
    2. Apparatus according to claim 1, characterized by the fact that at least one of the first sensor (260) and the second sensor (262) detects one of: acoustic waves, gamma rays, electromagnetic waves and a tracker.
    [0003]
    3. Apparatus according to claim 1, characterized by the fact that one of the first sensor (260) and the second sensor (262) is positioned on one of a rod (212b) and a section of the pin (312) of the drill bit (200).
    [0004]
    4. Apparatus according to claim 1, characterized by the fact that the processor (572) is configured to process measurements from the first sensor (260) and the second sensor (262) to match a characteristic of a formation and determine a ROP based on the first time, second time and a selected distance (264).
    [0005]
    5. Method for determining the rate of penetration of the drill bit (200) into the borehole (110), comprising: the identification of a selected feature in a selected location (358) of a formation involving a borehole (110) a first time using measurements from a first sensor (260) on the drill bit (200); identifying the selected feature at the selected location (358) a second time using measurements from a second sensor (262) on the drill bit (200); and calculating the penetration rate for the drill bit (200) based on the distance (264) between the first sensor (260) and the second sensor (262), the first time and the second time using the processor (572); the method characterized by the fact that the drill bit (200) comprises a recess area (515) that receives a sealing member (514) and is configured to be at a surface pressure, in which a controller (370) including the processor (572) is housed in the recessed area (515).
    [0006]
    6. Method, according to claim 5, characterized by the fact that the first and second sensors are configured to capture one of: acoustic waves, gamma rays, traces of chemicals and resistivity.
    [0007]
    7. Method according to claim 5, characterized by the fact that the first (260) and the second (262) sensors are positioned on a rod (212b), a crown (212a) and a drill bit pin ( 200).
    [0008]
    8. Method, according to claim 5, characterized in that it additionally comprises the digitization of the signals provided by the first sensor (260) and the second sensor (262) through a circuit.
    [0009]
    9. Method according to claim 6, characterized by the fact that the first sensor (260) is positioned on a rod (212b) of the drill bit (200) and the second sensor (262) is positioned on a crown ( 212a) and a pin.
    类似技术:
    公开号 | 公开日 | 专利标题
    BR112012005535B1|2021-02-09|apparatus for use in drilling a well hole and method for determining the drill penetration rate
    US8695728B2|2014-04-15|Formation evaluation using a bit-based active radiation source and a gamma ray detector
    US8210280B2|2012-07-03|Bit based formation evaluation using a gamma ray sensor
    CA2648698C|2013-07-30|Method and apparatus for determining formation resistivity ahead of the bit and azimuthal at the bit
    US9328561B2|2016-05-03|Drill bits with sensors for formation evaluation
    US6285026B1|2001-09-04|Borehole caliper derived from neutron porosity measurements
    US8573327B2|2013-11-05|Apparatus and methods for estimating tool inclination using bit-based gamma ray sensors
    BR112020012000A2|2020-11-17|systems and methods for downhole determination of drilling characteristics
    BR112013008331B1|2020-03-17|Drill detection and training evaluation
    US20140142855A1|2014-05-22|Wellbore Instrument Clock Oscillator and Instrument System Made Therewith
    US8481920B2|2013-07-09|Apparatus and method for determining formation density from nuclear density measurements made using sensors at more than one location
    US10921478B2|2021-02-16|Method and transducer for acoustic logging
    US20170321539A1|2017-11-09|Method for wellbore ranging and proximity detection
    Maranuk0|Acoustic MWD caliper improves accuracy with digital-signal technology March 2, 1998 A newly developed acoustic-caliper tool, utilizing digital-signal processing technology, has increased accuracy and operational range as compared to previous tools. The tool can be run alone or integrated with other MWD-type sensors. The advantages this tool has over other measurement-while-drilling | acoustic caliper tools are: Digitization of the acoustic pulse-echo signals The capability to perform digital-signal processing on the resulting waveforms The ability to analyze raw waveforms
    同族专利:
    公开号 | 公开日
    US9238958B2|2016-01-19|
    EP2475837B1|2020-07-08|
    EP2475837A2|2012-07-18|
    EP2475837A4|2015-08-19|
    WO2011031863A3|2011-06-30|
    CA2773057A1|2011-03-17|
    BR112012005535A2|2020-10-13|
    US20110060527A1|2011-03-10|
    CA2773057C|2016-08-16|
    WO2011031863A2|2011-03-17|
    WO2011031863A4|2011-08-04|
    引用文献:
    公开号 | 申请日 | 公开日 | 申请人 | 专利标题
    US5160925C1|1991-04-17|2001-03-06|Halliburton Co|Short hop communication link for downhole mwd system|
    US5237539A|1991-12-11|1993-08-17|Selman Thomas H|System and method for processing and displaying well logging data during drilling|
    NO930044L|1992-01-09|1993-07-12|Baker Hughes Inc|PROCEDURE FOR EVALUATION OF FORMS AND DRILL CONDITIONS|
    NO306522B1|1992-01-21|1999-11-15|Anadrill Int Sa|Procedure for acoustic transmission of measurement signals when measuring during drilling|
    US5679894A|1993-05-12|1997-10-21|Baker Hughes Incorporated|Apparatus and method for drilling boreholes|
    US5720355A|1993-07-20|1998-02-24|Baroid Technology, Inc.|Drill bit instrumentation and method for controlling drilling or core-drilling|
    US5475309A|1994-01-21|1995-12-12|Atlantic Richfield Company|Sensor in bit for measuring formation properties while drilling including a drilling fluid ejection nozzle for ejecting a uniform layer of fluid over the sensor|
    US5581024A|1994-10-20|1996-12-03|Baker Hughes Incorporated|Downhole depth correlation and computation apparatus and methods for combining multiple borehole measurements|
    US6571886B1|1995-02-16|2003-06-03|Baker Hughes Incorporated|Method and apparatus for monitoring and recording of the operating condition of a downhole drill bit during drilling operations|
    US6230822B1|1995-02-16|2001-05-15|Baker Hughes Incorporated|Method and apparatus for monitoring and recording of the operating condition of a downhole drill bit during drilling operations|
    US6408953B1|1996-03-25|2002-06-25|Halliburton Energy Services, Inc.|Method and system for predicting performance of a drilling system for a given formation|
    US6057784A|1997-09-02|2000-05-02|Schlumberger Technology Corporatioin|Apparatus and system for making at-bit measurements while drilling|
    US6347282B2|1997-12-04|2002-02-12|Baker Hughes Incorporated|Measurement-while-drilling assembly using gyroscopic devices and methods of bias removal|
    US6247542B1|1998-03-06|2001-06-19|Baker Hughes Incorporated|Non-rotating sensor assembly for measurement-while-drilling applications|
    US6429784B1|1999-02-19|2002-08-06|Dresser Industries, Inc.|Casing mounted sensors, actuators and generators|
    US6564883B2|2000-11-30|2003-05-20|Baker Hughes Incorporated|Rib-mounted logging-while-drilling sensors|
    US6850068B2|2001-04-18|2005-02-01|Baker Hughes Incorporated|Formation resistivity measurement sensor contained onboard a drill bit |
    US6467341B1|2001-04-24|2002-10-22|Schlumberger Technology Corporation|Accelerometer caliper while drilling|
    US6769497B2|2001-06-14|2004-08-03|Baker Hughes Incorporated|Use of axial accelerometer for estimation of instantaneous ROP downhole for LWD and wireline applications|
    GB2405483B|2002-05-13|2005-09-14|Camco Internat|Recalibration of downhole sensors|
    US7036611B2|2002-07-30|2006-05-02|Baker Hughes Incorporated|Expandable reamer apparatus for enlarging boreholes while drilling and methods of use|
    US7207215B2|2003-12-22|2007-04-24|Halliburton Energy Services, Inc.|System, method and apparatus for petrophysical and geophysical measurements at the drilling bit|
    GB2411726B|2004-03-04|2007-05-02|Schlumberger Holdings|Downhole rate of penetration sensor assembly and method|
    US7301473B2|2004-08-24|2007-11-27|Halliburton Energy Services Inc.|Receiver for an acoustic telemetry system|
    US7278499B2|2005-01-26|2007-10-09|Baker Hughes Incorporated|Rotary drag bit including a central region having a plurality of cutting structures|
    US7350568B2|2005-02-09|2008-04-01|Halliburton Energy Services, Inc.|Logging a well|
    US7604072B2|2005-06-07|2009-10-20|Baker Hughes Incorporated|Method and apparatus for collecting drill bit performance data|
    US7387177B2|2006-10-18|2008-06-17|Baker Hughes Incorporated|Bearing insert sleeve for roller cone bit|IL173670D0|2006-02-12|2008-01-20|Technion Res & Dev Foundation|Acoustic detector|
    EP2390461A1|2010-05-31|2011-11-30|Welltec A/S|Wellbore surveillance system|
    US9027670B2|2012-06-21|2015-05-12|Schlumberger Technology Corporation|Drilling speed and depth computation for downhole tools|
    US20140058677A1|2012-08-23|2014-02-27|Westerngeco, L.L.C.|Method for processing electromagnetic data|
    US9297251B2|2013-02-20|2016-03-29|Schlumberger Technology Corporation|Drill bit systems with temperature sensors and applications using temperature sensor measurements|
    EP2964882A1|2013-03-07|2016-01-13|Evolution Engineering Inc.|Detection of downhole data telemetry signals|
    CN104047592B|2013-03-15|2016-05-04|中国石油化工股份有限公司|A kind of method of utilizing time sharing method location drilling well microchip tracer depth|
    CN104047591B|2013-03-15|2016-06-29|中国石油化工股份有限公司|A kind of method utilizing pressure location drilling well microchip tracer depth|
    CN104047593B|2013-03-15|2016-05-04|中国石油化工股份有限公司|A kind of method of utilizing speed location drilling well microchip tracer depth|
    CA2933141A1|2014-01-02|2015-07-09|Shell Internationale Research Maatschappij B.V.|System and method for making downhole measurements|
    US9951606B2|2014-01-03|2018-04-24|Alcorp Ltd.|Directional drilling using mechanical waves detectors|
    WO2016099564A1|2014-12-19|2016-06-23|Halliburton Energy Services, Inc.|Roller cone drill bit with embedded gamma ray detector|
    GB2547585B|2014-12-30|2021-05-19|Halliburton Energy Services Inc|Systems and methods for estimating forces on a drill bit|
    WO2017105269A1|2015-12-15|2017-06-22|Baker Hughes Incorporated|Determination of concentration of chemical elements in an earth formation from non-coaxial dual detector radiation measurements|
    EP3724447A4|2017-12-15|2021-09-15|Baker Hughes Holdings Llc|Systems and methods for downhole determination of drilling characteristics|
    AU2019207660A1|2018-01-10|2020-07-02|Shell Internationale Research Maatschappij B.V.|Apparatus and method for downhole measurement|
    US11028685B2|2018-07-02|2021-06-08|Schlumberger Technology Corporation|Downhole rate of penetration measurement|
    US11111783B2|2019-08-06|2021-09-07|Halliburton Energy Services, Inc.|Estimating formation properties from drill bit motion|
    GB2586228A|2019-08-08|2021-02-17|Nemein Ltd|Sensor arrangement|
    法律状态:
    2020-09-29| B06U| Preliminary requirement: requests with searches performed by other patent offices: suspension of the patent application procedure|
    2020-12-22| B09A| Decision: intention to grant|
    2021-02-09| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 10 (DEZ) ANOS CONTADOS A PARTIR DE 09/02/2021, OBSERVADAS AS CONDICOES LEGAIS. |
    优先权:
    申请号 | 申请日 | 专利标题
    US12/557,004|US9238958B2|2009-09-10|2009-09-10|Drill bit with rate of penetration sensor|
    US12/557,004|2009-09-10|
    PCT/US2010/048277|WO2011031863A2|2009-09-10|2010-09-09|Drill bit with rate of penetration sensor|
    [返回顶部]