Integrated centerline data recorder

A system includes a sensor carrier and an integrated data recorder. The sensor carrier includes an outer sub body and an inner sub body. The inner sub body is coupled to the outer sub body by a support leg. The inner sub body includes a recess formed therein. The sensor carrier includes a flow path defined as the space between the outer sub body, the inner sub body, and the support leg. The integrated data recorder is positioned within the recess of the inner sub body such that the integrated data recorder is substantially at the centerline of the sensor carrier. The integrated data recorder includes a sensor package including one or more drilling dynamics sensors, a processor, a memory module, and an electrical energy source.

TECHNICAL FIELD/FIELD OF THE DISCLOSURE

The present disclosure relates generally to oilfield equipment, and specifically to integrated data recorders for oilfield equipment.

BACKGROUND OF THE DISCLOSURE

Wellbores are traditionally formed by rotating a drill bit positioned at the end of a bottom hole assembly (BHA). The drill bit may be actuated by rotating the drill pipe, by use of a mud motor, or a combination thereof. As used herein, the BHA includes the drill bit. Conventionally, BHAs may contain only a limited number of sensors and have limited data processing capability. The operating life of the drill bit, mud motor, bearing assembly, and other elements of the BHA may depend upon operational parameters of these elements, and the downhole conditions, including, but not limited to rock type, pressure, temperature, differential pressure across the mud motor, rotational speed, torque, vibration, drilling fluid flow rate, force on the drill bit or the weight-on-bit (“WOB”), inclination, total gravity field, gravity toolface, revolutions per minute (RPM), radial acceleration, tangential acceleration, relative rotation speed and the condition of the radial and axial bearings. The combination of the operational parameters of the BHA and downhole conditions are referred to herein as “drilling dynamics.”

To supplement conventional BHA sensors, drilling dynamics data may be measured by drilling dynamics sensors. Measurement of these aspects of elements of the BHA may provide operators with information regarding performance and may indicate need for maintenance.

SUMMARY

The present disclosure provides for a system. The system may include a sensor carrier. The sensor carrier may include an outer sub body and an inner sub body. The inner sub body may be coupled to the outer sub body by a support leg. The inner sub body may have a recess formed therein. The sensor carrier may include a flow path defined as the space between the outer sub body, the inner sub body, and the support leg. The system may include an integrated data recorder positioned within the recess of the inner sub body such that the integrated data recorder is substantially at the centerline of the sensor carrier. The integrated data recorder may include a sensor package including one or more drilling dynamics sensors, a processor in data communication with the one or more drilling dynamics sensors, a memory module in data communication with the one or more drilling dynamics sensors, and an electrical energy source in electrical communication with the memory module, the one or more drilling dynamics sensors, and the processor.

The present disclosure also provides for a system. The system may include a downhole tool having a bore. The system may include a sensor carrier coupled to the downhole tool and positioned within the bore of the downhole tool. The sensor carrier may include an outer sub body and an inner sub body. The inner sub body may be coupled to the outer sub body by a support leg. The inner sub body may have a recess formed therein. The sensor carrier may include a flow path defined as the space between the outer sub body, the inner sub body, and the support leg. The system may include an integrated data recorder positioned within the recess of the inner sub body such that the integrated data recorder is substantially at the centerline of the sensor carrier. The integrated data recorder may include a sensor package including one or more drilling dynamics sensors, a processor in data communication with the one or more drilling dynamics sensors, a memory module in data communication with the one or more drilling dynamics sensors, and an electrical energy source in electrical communication with the memory module, the one or more drilling dynamics sensors, and the processor.

DETAILED DESCRIPTION

FIG. 1depicts an embodiment of integrated data recorder100consistent with at least one embodiment of the present disclosure. The embodiment of integrated data recorder shown inFIG. 1is a “pressure barrel” design. Integrated data recorder100includes sensor package110. Sensor package110may include drilling dynamics sensors including, but not limited to, low-g accelerometers for determination of inclination, total gravity field, radial acceleration, tangential acceleration, and/or low-g vibration sensing; and/or gravity toolface; high-g accelerometers for shock sensing; temperature sensors; three-axis gyroscopes for rotation speed (angular velocity) computation; three-axis magnetometers for rotation speed (angular velocity) and toolface (angular position) computation; Hall-effect sensors to measure relative rotation speed, along with a magnetic marker or markers; one or more strain gauges to measure one or more of tension, compression, torque on bit, weight on bit, bending moment, bending toolface, and pressure. Sensor package110may include any or all of drilling dynamics sensors listed and may include other drilling dynamics sensors not listed. Sensor package110may include redundant sensors, for example and without limitation, two 3-axis low-g accelerometers and/or two 3-axis gyro sensors. Redundant sensors may improve reliability and accuracy. Further, the drilling dynamics sensors may be used for determination of other drilling dynamics data other than that listed. In certain embodiments, one or more of the drilling dynamics sensors may be digital, solid-state sensors. Digital, solid-state sensors may create less noise, have a smaller footprint, have lower mass, be more shock-resistant, be more reliable and have better power management than analog sensors. In some embodiments, one or more of the drilling dynamics sensors may be analog sensors. In some such embodiments, analog sensors may be used, for example and without limitation, with analog-to-digital converters. In certain embodiments, the accelerometers may be three-axis accelerometers. The three-axis accelerometers may be digital or analog sensors, including, but not limited to quartz accelerometers. In some embodiments, the gyroscopes may be three-axis gyroscopes.

As used herein, low-g accelerometers may measure up to between +/−16 G. As used herein, high-g accelerometers may measure up to between +/−200 G. Rotation speed in RPM (revolutions per minute) may be measured, for example, between 0 and 500 RPM. Temperature may be measured, for example, between −40° C. and 175° C., between −40° C. and 150° C. or between −40° C. and 125° C. As further described herein below, the measurement range of the sensors may be programmable while integrated data recorder100is within the wellbore. For example, the low-g accelerometers measurement range may be changed from +/−4 G to +/−16 G while drilling. For example, the high-g accelerometers measurement range may be changed from +/−100 G to +/−400 G while drilling.

With further attention toFIG. 1, integrated data recorder100may include memory module115in data communication with sensor package110. Memory module115is adapted to store data gathered by the sensors in sensor package110. Memory module115is in data communication with communication port120. Communication port120is adapted to provide a data communications link between memory module115and a surface processor. Communication port120may be adapted to communicate with other processors in a communication bus (e.g. MWD tool) via a common communication bus, for example, transmitting drilling dynamics data, statistics based on drilling dynamics data, rock mechanics information, or a combination thereof to surface via MWD.

Also depicted inFIG. 1is processor105. Processor105may be in data communication with the sensors in sensor package110and memory module115. Processor105may control the operation of the sensors in sensor package110, as described herein below. Processor105may include application software/firmware stored on a computer readable media, such as program Flash memory, which is part of Processor105. One non-limiting example of processor105with program Flash memory is a 16-bit microcontroller, Model SM470R1B1M-HT from Texas Instruments (Dallas, Tex., USA). The application software/firmware may include instructions, for example and without limitation, for executing deep-sleep mode, standby mode, and active mode, as described herein below. The application software/firmware in processor105may be loaded and replaced, via communication port bus176through communication port120, by a surface processor. Integrated data recorder100may further include a real-time clock, an oscillator, a fuse, and a voltage regulator. Processor105includes, but is not limited to a microcontroller, microprocessor, DSP (digital signal processor), DSP controller, DSP processor, FPGA (Field-Programmable Gate Array), GPU (Graphics Processing Unit) or combinations thereof.

Memory module115, processor105, and sensor package110and/or the sensors in sensor package110may be in electrical communication with electrical energy source130. Electrical energy source130provides power to processor105, memory module115, and the sensors in sensor package110. In some non-limiting embodiments, electrical energy source130may be a lithium battery. In yet other embodiments, electrical energy source130may be electrically connected to sensors in sensor package110indirectly through a voltage regulator. In other embodiments, electrical energy source130may be positioned in a package separate from sensor package110. In certain embodiments, electrical energy source130is a battery, such as a rechargeable battery or a non-rechargeable battery. In other embodiments, electrical energy source130may be a rechargeable or non-rechargeable battery with an energy harvesting device. In some embodiments, the energy harvesting device may be a piezo-electric energy harvester or a MEMS energy harvester. In some embodiments, the energy harvesting device may include a solenoid coil generator with one or more corresponding magnets positioned on a component of drill or tool string10.

As depicted inFIG. 1, processor105, sensor package110, memory module115, communication port120, and electrical energy source130may be housed within pressure barrel140. In the embodiment depicted inFIG. 1, pressure barrel140is cylindrical or generally cylindrical. In other embodiments, pressure barrel140may be of other shapes adapted to contain processor105, sensor package110, memory module115, communication port120, electrical energy source130, and wireless communications module122. In some embodiments, the pressure within pressure barrel140is atmospheric or near-atmospheric pressure. In some embodiments, the pressure rating for pressure barrel140may be at least 15,000 psi.

In some embodiments, the downhole battery life of electrical energy source130may be at least 240 hours (or 10 days), and in some embodiments, memory module115may have at least 16 M Bytes of storage. In some embodiments, memory module115may have up to 8 gigabytes of storage.

As further shown inFIG. 1, end caps125,135may be fitted to the ends of pressure barrel140. In some embodiments, one or more of pressure barrel140or end caps125,135may be formed from a generally electrically, magnetically, and/or electromagnetically transparent material. In some embodiments, for example and without limitation, pressure barrel140or end caps125,135may be formed from one or more of a polymer such as polyether ether ketone (PEEK), high-temperature rubber, high-temperature plastic, or high-temperature ceramic material. Depending on the operating conditions to which integrated data recorder100will be subjected, a material having high resilience, high mechanical, chemical, and temperature resistance may be used. For example, integrated data recorder100used in an oil or gas wellbore may encounter higher temperatures, pressures, and chemical reactivity than integrated data recorder100used in a mining operation, and may, accordingly, be built of more resilient materials.

In certain embodiments, communication port120may protrude through memory dump end cap125.

FIG. 2Adepicts integrated data recorder100coupled to drill string10. In some embodiments, integrated data recorder100may be coupled to drill string10by sensor carrier101. In some embodiments, sensor carrier101may be coupled to drill string10such that integrated data recorder100is positioned substantially at the center of sensor carrier101such that, for example and without limitation, integrated data recorder100is positioned substantially along or near the axis of rotation of drill string10. In some embodiments, integrated data recorder100may be positioned substantially aligned with the axis of rotation of drill string10. In some embodiments, integrated data recorder100may be positioned near the axis of rotation of drill string10but offset by a small distance. In some such embodiments, integrated data recorder100may be, for example and without limitation, within 3 inches of the axis of rotation, within 1 inch of the axis of rotation, or within 0.5 inches of the axis of rotation. As discussed below, integrated data recorder100may be used to measure one or more drilling dynamics parameters.

Because integrated data recorder100is positioned substantially along or near the axis of rotation of drill string10, components of integrated data recorder including, for example and without limitation, processor105, sensor package110, memory module115, communication port120, and electrical energy source130as discussed above, may be subjected to less shock and vibration during operation of drill string10when compared to an integrated data recorder100positioned at the periphery of the component of drill string10. Additionally, in embodiments in which sensor package110includes cross-axial accelerometers, there is less chance of saturating such cross-axial accelerometers when compared to an integrated data recorder100positioned at the periphery of the component of drill string10. Such saturation of a peripherally mounted integrated data recorder100may, for example and without limitation, occur repeatedly and rapidly during torsional oscillation or vibration of drill string10, preventing or reducing the reliability of the measurements taken by such a cross-axial accelerometer. The cross-axial accelerometer data may be used, for example and without limitation, for the calculation of geo-mechanics parameters, pseudo geo-physical parameters, and/or pseudo formation-evaluation parameters.

In some embodiments, wherein sensor package110includes a gyro having sensitive axis substantially aligned with the axis of rotation of drill string10, angular acceleration may be calculated from the gyro angular velocity by time-differentiating the angular velocity data. The tangential acceleration of the outer surface of the tool within which integrated data recorder100is positioned may be calculated by multiplying the derivative of the measured angular velocity (or angular acceleration) by the radius of the tool within which integrated data recorder100is positioned. Similarly, the radial acceleration may be calculated by multiplying the squared angular velocity by the radius of the tool within which integrated data recorder100is positioned. Alternatively, the angular velocity may be calculated from the accelerometer or magnetometer angular position by time-differentiating the angular position data. Alternatively, the angular acceleration may be calculated from the accelerometer or magnetometer angular velocity by time-differentiating the angular velocity data. In the drilling industry, an accelerometer angular position may be referred to as a gravity toolface (GTF). A magnetometer angular position may be referred to as a magnetic toolface (or MTF).

In some embodiments, sensor carrier101may be coupled to or formed as part of any component of a drill or tool string within a wellbore such as, for example and without limitation, a component of a BHA, drill bit, stabilizer, cross-over, drill pipe, drill collar, pin-box connection, jar, reamer, underreamer, friction reducing tool, string stabilizer, near-bit stabilizer, mud motor, turbine, stick-slip mitigation tool, or bearing housing. In some embodiments, sensor carrier101may be coupled to or formed as part of any steerable tool, including, for example and without limitation, a steerable motor, a steerable wired-motor, steerable turbine, steerable wired-turbine, steerable gear-reduced turbine, motor-assisted rotary-steerable tool, turbine-assisted rotary-steerable tool, gear-reduced turbine-assisted rotary-steerable tool, MWD (measurement-while-drilling) integrated steerable tool, or coiled tubing steerable tool. In some embodiments, sensor carrier101may be coupled to an oil and gas drilling string or may be coupled to or formed as part of a mining/coring tool or mining/coring string including a mining bit. In some embodiments, sensor carrier101may be coupled to or formed as part of a component of a drill or tool string located at the surface for drilling, coring and mining or may be coupled to or formed as part of a piece of equipment coupled to the drill string such as, for example and without limitation, a Kelly shaft, saver sub, or component of a top drive such as a quill.

In some embodiments, sensor carrier101may be included as part of carrier sub200as shown inFIGS. 2A-2D. Carrier sub200may, in some embodiments, include threaded connections to allow carrier sub200to mechanically couple between tubulars10a,10bof drill string10. Tubulars10a,10bmay be tubular segments of drill string10, may be components of tools of drill string10, or may be a combination thereof. In some embodiments, carrier sub200may include outer sub body201and inner sub body203. In some such embodiments, integrated data recorder100may be positioned within inner sub body203. In some embodiments, integrated data recorder100may be positioned within recess205formed within inner sub body203and may be retained therein by retention cap207. Retention cap207may be, for example and without limitation, threadedly coupled to inner sub body203.

In some embodiments, carrier sub200may include flowpaths209, shown inFIGS. 2B-2D, formed between outer sub body201and inner sub body203to, for example and without limitation, allow for fluid flow from the bore of tubular10ato the bore of tubular10bthrough carrier sub200, thereby allowing continuous fluid flow through drill string10. In some embodiments, carrier sub200may include one or more support legs211extending between outer sub body201and inner sub body203to, for example and without limitation, support inner sub body203within outer sub body201. Flowpaths209may be defined by the space between outer sub body201, inner sub body203, and support legs211.

In some embodiments, sensor carrier101may be included as part of insert sub300as depicted inFIGS. 3A-C. Insert sub300may be positioned within the bore301of tubular303. Tubular303may include one or more retention features305such as lips, flanges, or upsets in the wall of bore301to allow insert sub300to be positioned therein.

In some such embodiments, integrated data recorder100may be positioned within inner sub body307of insert sub300. In some embodiments, integrated data recorder100may be positioned within recess309formed within inner sub body307and may be retained therein by retention cap311. Retention cap311may be, for example and without limitation, threadedly coupled to inner sub body307.

In some embodiments, insert sub300may include flowpaths313formed between outer sub body315and inner sub body307to, for example and without limitation, allow for fluid flow through bore301of tubular303through insert sub300, thereby allowing continuous fluid flow through tubular303. In some embodiments, insert sub300may include one or more support legs317extending between outer sub body315and inner sub body307to, for example and without limitation, support inner sub body307within outer sub body315. Flowpaths313may be defined by the space between outer sub body315, inner sub body307, and support legs317. In some embodiments, outer sub body315may mechanically couple to tubular303.

In some embodiments, insert sub300may be positioned within a tubular segment of drill string10, a tool of drill string10, or component of a tool of drill string10. For example and without limitation, in some embodiments, tubular303, as depicted inFIG. 3A, may be a tubular member such as a drillpipe or other sub coupled between other tubular members of drill string10. Including insert sub300within tubular303may, for example and without limitation, allow integrated data recorder100to be positioned along drill string10at a desired location by including tubular303into drill string10.

In some embodiments, as depicted inFIGS. 4A, 4B, insert sub300may be positioned within rotor catch housing401of rotor catch assembly400. Rotor catch housing401may include rotor catch bore403and may be used as understood in the art to control or constrain movement of rotor405of a downhole motor. Insert sub300may be inserted into rotor catch bore403and coupled to rotor catch housing401. In such an embodiment, rotor catch housing401may include retention features407as discussed above that may allow insert sub300to be positioned within rotor catch bore403. Integrated data recorder100may thereby be located at a position within rotor catch assembly400.

In some embodiments, as depicted inFIG. 5, insert sub300may be positioned within bit box500. In some embodiments, bit box500may be a part of shaft501of a downhole motor or rotary steerable system. Bit box500and shaft501may include shaft bore503. Insert sub300may be inserted into and coupled to shaft bore503of bit box500and shaft501. In such an embodiment, bit box500or shaft501may include retention features505as discussed above that may allow insert sub300to be positioned within bit box500and shaft501. Integrated data recorder100may thereby be located at a position within bit box500or shaft501proximate to drill bit507.

In some embodiments, sensor carrier101may be integrated into a tool of drill string10. For example, as depicted inFIGS. 6A, 6B, sensor carrier601may be formed as part of drill bit600. Although drill bit600is depicted as a fixed cutter (PDC) bit having fixed cutters617, sensor carrier101may be integrated into a roller cone bit, mill tooth bit, diamond drill bit, impregnated diamond drill bit, hybrid bit, or any other type of drill bit without deviating from the scope of the present disclosure. In such an embodiment, sensor carrier601may include outer carrier body603and inner carrier body605. Outer carrier body603may form a part of drill bit600or may be otherwise integrally formed with drill bit600. In some embodiments, integrated data recorder100may be positioned within inner carrier body605. In some embodiments, integrated data recorder100may be positioned within recess607formed within inner carrier body605and may be retained therein by retention cap609. Retention cap609may be, for example and without limitation, threadedly coupled to inner carrier body605. Although depicted as being positioned near pin619of drill bit600, in some embodiments, sensor carrier101may be located at a position further away from pin619without deviating from the scope of this disclosure. For example, sensor carrier101may be positioned within a plenum of drill bit600.

In some embodiments, drill bit600may include flowpaths611formed between outer carrier body603and inner carrier body605to, for example and without limitation, allow for fluid flow through nozzles615of drill bit600. In some embodiments, drill bit600may include one or more support legs613extending between outer carrier body603and inner carrier body605to, for example and without limitation, support inner carrier body605within outer carrier body603. Flowpaths611may be defined by the space between outer carrier body603, inner carrier body605, and support legs613. By positioning integrated data recorder100within recess607of sensor carrier601integrated into drill bit600, integrated data recorder100may thereby be positioned at a location proximate the drilling end of drill string10. Because integrated data recorder100is located near the cutting action of drill bit600, valuable vibration and shock information may be gathered.

In some embodiments, integrated data recorder100may include location pin145as depicted inFIG. 7. In some embodiments, location pin145may engage with locator slot147formed in sensor carrier101. In some such embodiments, location pin145may prevent or reduce rotation of integrated data recorder100during operation while integrated data recorder100is positioned within sensor carrier101.

FIG. 8depicts a block diagram of integrated data recorder100. Integrated data recorder includes sensor package110which includes one or more sensors. In the embodiment shown inFIG. 8, the sensors may include one or more of low-g accelerometer111, high-g accelerometer112, gyroscope113, and temperature sensor114. In some embodiments, such as the embodiment shown inFIG. 8, the sensors may also include one or more of magnetometer116, pressure sensor117, and strain gauge (e.g. weight sensor, bending moment sensor, pressure sensor, etc.)119. In other embodiments, sensor package110may include any of sensors111,112,113,114,116,117, and119. Sensors111,112,113,114,116,117, and119may be in data communication with processor105through sensor communication bus170. Sensor communication bus170may be a digital communication bus, such as an SPI (Serial Peripheral Interface) bus or an I2C (Inter-Integrated Circuit) bus.

In certain embodiments, Hall-effect sensor118may be in data communication with processor105through Hall-effect sensor bus172. Hall-effect sensor bus172may be a digital communication bus, such as an SPI or an I2C bus. In some embodiments, Hall-effect sensor118is directly connected to processor105via an input port, for example, an interrupt pin or an analog-to-digital-converter pin. In other embodiments, Hall-effect sensor118may be a digital Hall-effect sensor or analog (ratio-metric) Hall-effect sensor. In other embodiments, Hall-effect sensor118may be omitted.

In the embodiment depicted inFIG. 8, memory module115is in data communication with processor105through memory communication bus174. Memory communication bus174may be a CAN (Controller Area Network) bus, an SPI or an I2C bus in certain non-limiting examples. Thus, sensors111,112,113,114,116,117, and119are in data communication with memory module115through sensor communication bus170, processor105, and memory communication bus174. Hall-effect sensor118is in data communication with memory module115through Hall-effect sensor bus172, processor105and memory communication bus174. Memory module115may contain multiple memory devices, such as between 2 and 8 memory devices or 4 memory devices. Each memory device may be a non-volatile memory medium, such as Flash or EEPROM (Electrically Erasable Programmable Read-Only Memory) device. One non-limiting example of EEPROM device is a 1-kbit SPI EEPROM, Model 25LC010A from Microchip (Chandler, Ariz., USA).

As further shown inFIG. 8, processor105is in data communication with communication port120through communication port bus176. Communication port bus176may be a digital communication bus, including, but not limited to, a SCI (Serial Communication Interface) bus, a UART (Universal Asynchronous Receiver/Transmitter) bus, a CAN bus, a SPI bus or a I2C bus. Communication port120may be in data communication with memory module115through memory communication bus174, processor105, and communication port bus176. One non-limiting example of processor105with such communication bus feature is a 16-bit microcontroller, Model SM470R1B1M-HT from Texas Instruments (Dallas, Tex., USA).

In some embodiments, as further shown inFIG. 8, processor105may be in data communication with wireless communications module122through wireless communication bus177. Wireless communication bus177may be a digital communication bus, including, but not limited to, a SCI (Serial Communication Interface) bus, a UART (Universal Asynchronous Receiver/Transmitter) bus, a CAN bus, a SPI bus or a I2C bus. Wireless communications module122may be in data communication with memory module115through memory communication bus174, processor105, and wireless communication port bus177. Wireless communications module122may, in some embodiments, allow for wireless communication between integrated data recorder100and external device180as further discussed below. External device180may be, for example and without limitation, one or more of a computer, mobile device, personal computer, tablet, smartphone, external data logger, or other suitable system. Wireless communications module122may, for example and without limitation, allow for data from memory module115to be transmitted to external device180without physically interacting with integrated data recorder100. In some embodiments, external device180may upload or stream data from integrated data recorder100to a remote location such as, for example and without limitation, a server or cloud network. In some embodiments, integrated data recorder100may remain installed to sensor carrier101while data is retrieved from memory module115. In some embodiments, wireless communications module122may, for example and without limitation, allow for data/commands from external device180to be received by processor105without physically interacting with integrated data recorder100. In some embodiments, the operational setting of integrated data recorder100may be changed wirelessly. In some embodiments, external device180may be surface equipment with Internet connection or a downhole tool within a drillstring.

Wireless communications module122may use any wireless communication protocol for communicating between integrated data recorder100and external device180including, for example and without limitation, one or more of Wi-Fi, Bluetooth, Bluetooth low energy (BLE), ZigBee, Z-Wave, GSM (Global System for Mobile Communications), CDMA (Code-division multiple access), UMTS (Universal Mobile Telecommunications System), LTE (Long-Term Evolution), GPS (Global Positioning System), satellite communication, or any other wireless communication protocol.

In some embodiments, wireless communications module122may be a transceiver such that data or commands transmitted from external device180may be received by integrated data recorder100. In some such embodiments, external device180may send instructions to integrated data recorder100to, for example and without limitation, configure one or more parameters of sensor package110or configure an operational mode of integrated data recorder100. In some embodiments, for example and without limitation, synchronization or calibration of sensors or other parameters of integrated data recorder100may be accomplished using commands transmitted wirelessly from external device180to wireless communications module122.

FIG. 9depicts another embodiment of a block diagram of integrated data recorder100. InFIG. 9, sensor communication bus170and memory communication bus174are connected to form sensor-memory bus175.

In the embodiments shown inFIGS. 8 and 9, electrical energy source130is in electrical connection with each of sensors111,112,113,114,116,117,119, processor105, memory module115, and wireless communications module122. In some embodiments, electrical energy source130may be electrically connected to each of sensors111,112,113,114,116,117,119directly. In other embodiments, electrical energy source130may be electrically connected to each of sensors111,112,113,114,116,117,119indirectly through a connection to sensor package110. In yet other embodiments, electrical energy source130may be electrically connected to each of sensors111,112,113,114,116,117,119indirectly through a voltage regulator.

In some embodiments, communication port120may include a power bus used to provide power to recharge electrical energy source130. In some embodiments, integrated data recorder100may include one or more wireless charging apparatuses to, for example and without limitation, allow electrical energy source130to be charged without dismantling integrated data recorder100.

In some embodiments, multiple integrated data recorders100may be included within a single drill string or tool string coupled to various tools at various locations throughout the drill string or tool string. In some embodiments, integrated data recorders100may be located within both downhole and surface tools of the drill string or tool string.

In operation, the sensors in sensor package110of one or more integrated data recorders100within the wellbore may measure drilling dynamics data. The drilling dynamics data may be stored in memory module115, referred to herein as “memory logging,” during the drilling process. When integrated data recorder100is retrieved from the wellbore and positioned at the surface, drilling dynamics data may be retrieved from memory module115through wireless communications module122or by connecting to communication port120.

In some embodiments, external device180at the surface may include a surface processor connected to a cloud data storage and computing server. In some such embodiments, the wirelessly retrieved data may be stored in the cloud data storage and may be processed in the cloud server. For example and without limitation, in some embodiments, a run summary, including rotating hours, flow-on hours, vibration-on hours, shock statistics, stick-slip statistics, or other data gleaned from integrated data recorders100may be generated in the cloud server and sent to one or more client devices via the Internet. In some embodiments, both surface recorded drilling dynamics data and downhole recorded drilling dynamics data may be quality-controlled (QC'ed), in the cloud computing system, and combined with data from a surface Electronic Drilling Recorder (EDR). In some embodiments, a drilling dynamics log and accelerometer/gyro spectrograms, such as in JPEG (Joint Photographic Experts Group), PDF (Portable Document Format), may be generated in the cloud computing system. In some embodiments, one or more pattern recognition algorithms (e.g. based on artificial intelligence and machine learning) may be run on the combined data sets to identify, for example and without limitation, operational anomalies and/or data anomalies.

In some embodiments, drilling dynamics data recorded by integrated data recorder100may be used for post-run and/or continuous (in the case of surface tools including integrated data recorders100) evaluation of drilling dynamics, frequency spectrum, statistical analysis, and Condition Based Monitoring/Maintenance (CBM). In some embodiments, frequency spectrum analysis may be done, for example, by applying discrete Fourier transform (or fast Fourier transform) to burst data. In some embodiments, statistical analysis may be done including, for example and without limitation, calculating minimum, maximum, median, mean, mode, root-mean-squared values, standard deviation, and variance of burst data. Statistical analysis may include making histograms of, for example, temperature, vibration, shock, inclination, rotation speed, rotation speed standard deviation, and vibration/shock standard deviation. Temperature histograms may include, for example, accumulating the data points in certain temperature bins over multiple deployments (runs) of the sensors and downhole tools.

CBM is maintenance performed when a need for maintenance arises. This maintenance is performed after one or more indicators show that equipment is likely to fail or when equipment performance deteriorates. CBM may apply systems that incorporate active redundancy and fault reporting. CBM may also be applied to systems that lack redundancy and fault reporting.

CBM may be designed to maintain the correct equipment at the right time. CBM may be based on using real-time data, recorded data, or a combination of real-time and recorded data to prioritize and optimize maintenance resources. Observing the state of a system is known as condition monitoring. Such a system will determine the equipment's health, and act when maintenance is necessary. Ideally, CBM will allow the maintenance personnel to do only the right things, minimizing spare parts cost, system downtime and time spent on maintenance.

Drilling dynamics data, such as high-frequency continuously sampled and recorded data, wherein high-frequency data refers to data at 800 Hz-6400 Hz, may be used for rock mechanics/rock physics analysis. Such rock mechanics analysis include the analysis/identification of fractures, fracture directions, rock confined/unconfined compressive strength, Young's modulus of elasticity, shear modulus, and Poisson's ratio. Such rock mechanics analysis may be accomplished by combining with surface measured parameters, such as WOB (weight on bit), TOB (torque on bit), RPM (revolutions per minute), ROP (rate of penetration), and flow rate. Pseudo formation-evaluation log (or Pseudo rock-physics log), such as pseudo-sonic log, pseudo-neutron log, pseudo-porosity log, pseudo-density log, pseudo-Gamma log may be generated with a combination of the analysis of high-frequency continuously sampled and recorded data, along with surface parameters, and other formation-evaluation data, such as natural Gamma log and other logging-while-drilling (LWD) logs. Alternatively, high-frequency continuously-sampled data (e.g. at 800 Hz-6400 Hz) may be used for real-time rock mechanics analysis. Rock mechanical parameters may also be referred to as geomechanical parameters. Alternatively, pseudo-formation evaluation log, such as pseudo-Gamma log may be generated downhole and transmitted to the surface for real-time geo-steering.

Power from electrical energy source130may be supplied to the sensors in sensor package110. In some embodiments, the electrical power from electrical energy source130to the sensors in sensor package110is always on (powered up) but at different levels. At the lowest power level, which in some embodiments may be used while integrated data recorder100are being transported, integrated data recorder100may be in “deep-sleep mode.” In deep sleep mode, the real-time clock, sensors, for example, sensors111,112,113,114,116,117and119, memory module115, and voltage regulator are powered off and processor105is placed in sleep mode. In certain embodiments, current consumption of this deep-sleep mode may be between 1 uA and 200 uA. In sleep mode, processor105does not function, except to receive a “wake-up” signal. The wake-up signal may, in some embodiments, be received through wireless communications module122. In some embodiments, integrated data recorder100may be placed in deep sleep mode by a software command to processor105received through wireless communications module122. Integrated data recorder100may be transitioned from deep-sleep mode to standby mode by communicating the wake-up signal to processor105through wireless communications module122while processor105is in passive mode. In some embodiments, processor105may be woken up by one or more active mode predetermined event criteria including, for example and without limitation, an inclination trigger, RPM trigger, temperature trigger, vibration trigger, or pressure trigger, in which a certain inclination of sensor carrier101, rotation rate of sensor carrier101, temperature measurement, vibration of sensor carrier101, or pressure measurement, respectively, measured by one or more corresponding sensors of sensor package110of integrated data recorder100causes processor105to enter the standby or operational state.

Deep-sleep mode may, for example and without limitation, extend battery life during transportation and/or storage without requiring physical disassembly of integrated data recorder100. Physical disassembly of integrated data recorder100may damage seals, threads, wires, and other elements if done by an unfamiliar technician in a remote location. The recorder may be in “deep-sleep mode” for as much as between 1 month and 1 year before it is sent downhole for dynamics data logging.

In standby mode, processor105and at least one sensor (active sensor) of sensor package110are active. Digital solid-state sensors may be put into standby mode using a digital command. Standby current to remaining sensors of sensor package110may be around 1 μA to 200 uA. Once an active mode predetermined event criterion is met, as determined, for example, by the active sensor, processor105sends a command to the remaining sensors of sensor package110to begin measurement of data and to memory module115to begin logging data (“active mode”).

The active mode predetermined event criterion may be, for example, a temperature, pressure, acceleration, acceleration standard deviation, rotation speed standard deviation, or inclination threshold as determined by the active sensor. The active mode predetermined event may also be a drill string or bit rotation rate threshold. In some embodiments, the active mode predetermined event criterion may be a combination of one or more of a temperature threshold, pressure threshold, acceleration threshold, acceleration standard deviation threshold, rotation speed standard deviation threshold, inclination threshold, drill string rotation rate threshold, or bit rotation rate threshold. In some embodiments, the active mode threshold that predetermines event criterion may be stored in digital, solid-state sensors, which may generate interrupt events to processor105. For example, one non-limiting example of a digital, solid-state sensor with such feature is an I2C digital temperature sensor, Model MCP9800 from Microchip (Chandler, Ariz., USA). Temperature thresholds with hysteresis (e.g. upper threshold and lower threshold) may be stored in MCP9800. In certain embodiments, all sensors are non-active during standby mode and the drill string or bit rotation (using accelerometers, gyros, magnetometers or a combination thereof) may be communicated to and received by integrated data recorder100via downlink communication from the surface. In certain embodiments, downlink communication may be accomplished by mud-pulse telemetry, electro-magnetic (EM) telemetry, wired-drill-pipe telemetry or a combination thereof. In other embodiments, downlink communication may be accomplished by varying the drill string rotation rate, for example and not limited to the method described in US Patent Publication No. 2017/0254190, entitled System and Method for Downlink Communication, published Sep. 7, 2017.

In certain embodiments, during active mode, once a predetermined passive mode criterion has been met, processor105may send a command to the sensors of sensor package110and memory module115to return to standby mode, thereby discontinuing measurement of data by the sensors and logging of data by memory module115. The passive mode predetermined event criterion may be, for example, a temperature threshold, pressure threshold, acceleration threshold, acceleration standard deviation threshold, RPM threshold, or inclination threshold as determined by one or more sensors of sensor package110. In some embodiments, the passive mode thresholds that predetermine event criterion may be stored in digital, solid-state sensors, which may generate interrupt events to processor105. One non-limiting example of digital, solid-state sensor with such feature is an I2C digital temperature sensor, Model MCP9800 from Microchip (Chandler, Ariz., USA). Temperature thresholds with hysteresis (e.g. upper threshold and lower threshold) may be stored in MCP9800. In one non-limiting example, the digital, solid state sensor made may change from the passive mode (no logging) to the active mode (logging) and from the active mode (logging) to the passive mode (no logging) multiple times, based on one or more, or a combination of event thresholds.

In active mode, sensors in sensor package110are turned on for a predetermined duration at a predetermined log interval for measurement of drilling dynamics data. Examples of predetermined duration include 1-10 seconds. Examples of predetermined log intervals are every 1, 2, 5, 10, 20, 30, or 60 seconds and durations between those values. Predetermined log intervals for each of the sensors in sensor package110may be the same or different. Predetermined durations for each of the sensors in sensor package110may be the same or different.

In certain embodiments, the sensors of sensor package110record burst data to memory module115at a burst data frequency. In some embodiments, the burst data frequency may, for example and without limitation, be 20 Hz or more, 50 Hz or more, 100 Hz or more 200 Hz or more, 400 Hz or more, 800 Hz or more, 1600 Hz or more, 3200 Hz or more, or 6400 Hz or more. Examples of burst data log interval include every 1, 2, 5, 10, 20, 30, or 60 seconds. The sensor burst data may be buffered in digital sensors in the built-in sensor memory, which may be configured as FIFO (first-in first-out) memory. In certain embodiments, processor105does not store sensor burst data in processor's RAM (random access memory), i.e., sensor data is sent directly from the sensors in sensor package110to memory module115. In certain embodiments, processor105may store a predetermined number of samples of sensor burst data (for example, just one sample of sensor burst data) in the RAM of processor105prior to sending the sensor burst data to memory module115. In other embodiments, high-frequency sampling data, for example, at 6400 Hz, is continuously stored to memory module115, such as continuously bursting and recording.

The use of the FIFO memory of a sensor may reduce processor105processing capability requirements and processor105power consumption. In certain embodiments, the number of the FIFO memories of a sensor may be between 32 and 1025 data points, or between 32 and 512 data points per sensor axis. One FIFO memory may hold, for example, 16 bits or 32 bits, depending on the sensor output resolution. For example, a 3-axis sensor may contain up to 16-bit×100-points×3-axis=48000 bits of FIFO memory. In some embodiments, the sensors of sensor package110may record statistics of some or each of the sensors. For example, the statistics of the high-g 3-axis accelerometer data, such as minimum, maximum, mean, median, root-mean-squared, standard deviation, and variance values may be recorded by the sensor package and, in certain embodiments, transmitted to memory module115. In some embodiments, sensor package110may record burst data of the low-g 3-axis digital accelerometer data 3-axis magnetometers and 3-axis digital gyroscope. In other embodiments, sensor package110may record continuously sampled data, for example, at 3200 Hz, of the 3-axis digital accelerometer data and 3-axis digital gyroscope. Raw analog-to-digital counts for accelerometers and gyroscopes, i.e., a number representing voltage, may be recorded in memory module115without temperature calibration or conversion to final units. In certain embodiments, temperature calibration may be performed by processor105for drilling dynamics data measured by the sensors of sensor package110. Temperature calibration may correct for the scale drift factor and offset drift over temperature. In certain embodiments, temperature calibration may be accomplished, for example, by look-up tables.

In some embodiments, ranges of some or all of the sensors in sensor package110may be changed while integrated data recorder100is within the wellbore. For example, the low-G accelerometer sensing range is programmable and changeable downhole from +/−4 G to +/−16 G and all ranges therebetween. For example, the high-G accelerometer sensing range may be programmable and changeable downhole from +/−100 G to +/−400 G and all ranges therebetween. Ranges may be changed based on attainment of a predetermined range threshold value or by communication by downlink from the surface. Examples of predetermined range thresholds include, but are not limited to values of rotation speed standard deviation, acceleration standard deviation, or combinations thereof.

In certain embodiments, sampling frequency of some or all of the sensors in sensor package110may be changed while integrated data recorder100is within the wellbore. Sample frequency may be changed based on attainment of a predetermined sampling threshold value or by communication by downlink from the surface. Examples of predetermined sampling thresholds include, but are not limited to, values of rotation speed standard deviation, acceleration standard deviation, or combinations thereof.

In some embodiments, some or all of the sensors in sensor package110may include an anti-aliasing filter on one or all of the axes of the sensor. The frequency of the anti-aliasing filter may be changed while integrated data recorder100is within the wellbore. For example, the anti-aliasing filter may be changed to between 25 Hz and 6400 Hz for accelerometers. In some embodiments, the anti-aliasing filter frequency may be changed when sampling frequency is changed to avoid aliasing.

In some embodiments, integrated data recorder100may with an MWD tool through communications port120or through wireless communications module122. In one non-limiting example, statistics of downhole dynamics data (for example, maximum shock, RPM standard deviation, root-mean-squared shock, mean vibration, median inclination, etc.) may be transmitted to surface via an MWD mud-pulse telemetry, electro-magnetic (EM) telemetry, EM short-hop telemetry, wired-drill-pipe telemetry or a combination thereof. In some embodiments, the sensor data may be transmitted to the MWD tool wirelessly. For example, an at-bit integrated data recorder100may transfer the sensor data from the bit to an MWD tool with a wireless module, via integrated data recorders100placed at multiple locations in a bottom-hole assembly (BHA). A wireless network, such as, for example and without limitation, Z-wave, may allow the data transferred from one device to another via other wireless modules using Z-wave's source-routed mesh network architecture. In some embodiments, the MWD tool may relay the drilling dynamics data to surface via a communications channel including, for example and without limitation, mud-pulse telemetry, electro-magnetic (EM) telemetry, EM short-hop telemetry, wired-drill-pipe telemetry or a combination thereof. In some embodiments, wireless integrated data recorders placed at many different positions in a drill string may relay at-bit sensor information from a bit to surface, such as, for example, for real-time geo-steering applications.

In some embodiments, integrated data recorder100may be used with an inductive coupler described in U.S. Pat. No. 10,119,343 “Inductive coupling”. In some such embodiments, inner annular segment as described therein may be mechanically coupled to outer annular segment by three radial spokes. The radial spokes may define flow paths through which fluid may pass between the integrated data recorder and collar through the sub.

In some embodiments, integrated data recorder100may be positioned in an existing tool. In some embodiments, integrated data recorder100may be added to the downhole tool without altering the tool length or mechanical integrity of the tool. In some such embodiments, a slot as described herein above may be formed in one or more components of the existing tool, and one or more integrated data recorders100may be placed therein.

In some embodiments, integrated data recorder100may be utilized during transportation of sensor carrier101. In such an embodiment, integrated data recorder100may measure one or more aspects of the movement of sensor carrier101including, for example and without limitation, the location of sensor carrier101and one or more parameters relating to the handling of sensor carrier101including detection of drops, shock loads, or other mishandling of sensor carrier101.

In some embodiments, information about the operation of bottom-hole assembly (BHA) may be transmitted to the surface via mud pulse telemetry. In some embodiments, temperature difference, temperature gradient, and other drilling dynamics information may be classified into different severity levels, for example, 4 to 8 severity levels indicative of a measured condition. As a non-limiting example, in embodiments in which 2-bit severity levels (4 levels) are used, a temperature difference may be coded as Level 1 which may be between 0 and 2 degrees centigrade, Level 2 between 2 and 4 degrees centigrade, Level 3 between 4 and 6 degrees centigrade, and Level 4 above 6 degrees centigrade. Similarly, downhole acceleration events or shocks may be coded as Level 1 (no shock) between 0 and 10 g, Level 2 (low) between 10 and 40 g, Level 3 (medium) between 40 and 100 g, and Level 4 (high) above 100 g. As another example, high-frequency torsional oscillation (HFTO) may be detected with tangential acceleration measurement or angular gyro measurement with an expected frequency range, for example, between 100 and 1600 Hz. Angular acceleration can be calculated by time-differentiating the angular gyro velocity. By applying a digital band-pass, digital band-reject, analog band-pass, analog band-reject, high-pass filter, digital high-pass filter, analog high-pass filter, or a combination thereof on a tangential accelerometer or gyro, downhole HFTO events may be coded as Level 1 (no HFTO) between 0 and 10 g, Level 2 (low HFTO) between 10 and 40 g, Level 3 (medium HFTO) between 40 and 100 g, and Level 4 (high HFTO) above 100 g. Alternatively, at integrated data recorder, filtered accelerations (for example, tangential accelerations, lateral accelerations, radial accelerations, angular accelerations, axial accelerations, etc.) may be used to estimate pseudo-formation-evaluation parameters, such as pseudo-sonic log, pseudo-neutron log, pseudo-porosity log, pseudo-density log, and pseudo-Gamma log. Pseudo formation-evaluation parameters and/or their severity levels may be transmitted to surface for geo-steering.

Rock mechanics parameters (e.g. Young's modulus, shear modulus, Poisson's ratio, compressive strength, and Fractures) may be detected with tri-axial high-frequency acceleration measurement with an expected frequency range, for example, between 100 and 1000 Hz, as described, for example in SPWLA 2017—“A Novel Technique for Measuring (Not Calculating) Young's Modulus, shear modulus, Poisson's Ratio and Fractures Downhole: A Bakken Case Study”. By applying a digital band-pass, digital band-reject, analog band-pass, analog band-reject, digital high-pass filters, analog high-pass filters, or a combination thereof on the at least one accelerometer or gyro, downhole fractures may be coded as Level 1 (no fractures) between 0 and 10, Level 2 (low) between 10 and 40, Level 3 (medium) between 40 and 100, and Level 4 (high) above 100 (the numbers are without units, but correlated to the number of fractures). Rock mechanics parameters and/or their severity levels may be transmitted to surface for geo-steering.

In some embodiments, more than one sensor may be used on the centerline in all tools mentioned herein. For example, in some embodiments, two or more integrated data recorders100may be included within a single tool.

In some embodiments, as depicted inFIG. 10, the tool into which insert sub300is located may include one or more additional sensors. For example and without limitation, in some embodiments, tubular303′ may include sensor pocket304′ adapted to receive an additional integrated data recorder100′. Additional integrated data recorder100′ may, in some embodiments, operate in conjunction with integrated data recorder100positioned at or near the axis of rotation of tubular303′ to, for example and without limitation, improve the accuracy of drilling dynamics measurement.