EP2807333B1 - Taux de pénétration de forage de haute définition pour forage marin - Google Patents

Taux de pénétration de forage de haute définition pour forage marin Download PDF

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Publication number
EP2807333B1
EP2807333B1 EP13734149.1A EP13734149A EP2807333B1 EP 2807333 B1 EP2807333 B1 EP 2807333B1 EP 13734149 A EP13734149 A EP 13734149A EP 2807333 B1 EP2807333 B1 EP 2807333B1
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EP
European Patent Office
Prior art keywords
sensor
drill
marine
marine drill
information
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Not-in-force
Application number
EP13734149.1A
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German (de)
English (en)
Other versions
EP2807333A2 (fr
Inventor
Trenton Martin
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Transocean Sedco Forex Ventures Ltd
Original Assignee
Transocean Sedco Forex Ventures Ltd
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US13/741,990 external-priority patent/US9217290B2/en
Application filed by Transocean Sedco Forex Ventures Ltd filed Critical Transocean Sedco Forex Ventures Ltd
Publication of EP2807333A2 publication Critical patent/EP2807333A2/fr
Application granted granted Critical
Publication of EP2807333B1 publication Critical patent/EP2807333B1/fr
Not-in-force legal-status Critical Current
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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00—Special methods or apparatus for drilling
    • E21B7/12—Underwater drilling
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B45/00—Measuring the drilling time or rate of penetration
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/001—Survey of boreholes or wells for underwater installation
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/04—Measuring depth or liquid level
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling

Definitions

  • the instant disclosure relates to marine drilling. More specifically, this disclosure relates to monitoring equipment for marine drilling.
  • the crown block position is an important consideration.
  • the top drive may be the primary point of attachment of the drill string to the rig.
  • the instrument for measuring block position is a rotary encoder.
  • Various types and attachment configurations of this encoder exist.
  • the drill floor is a primary consumer of the block position information, due to the highly automated nature of drilling systems.
  • the automation system monitors the block position for various control loops and safety interlocks.
  • the other consumer of the block position data is third party service companies on board the MODU, such as mud loggers, measurement while drilling service providers, logging while drilling service providers, and directional drillers.
  • the encoder's placement on the drill floor has advantages and tradeoffs.
  • the most convenient and reliable location for the encoder is mounted on the shaft of the draw works.
  • the main advantage when mounted on the shaft is that the location allows for easy installation and maintenance.
  • the drawback of this location is that systematic errors may be produced, because the encoder's observation is an indirect measurement.
  • This placement for the encoder measures the drums' current rotation angle.
  • Calibration is necessary to derive the block position. Calibration may be performed by using a direct distance measuring device such as a tape measure or electronic distance measurement (EDM) to generate a look-up table of block position to rotation increment. Placing the encoder on the rotary shaft of the draw works introduces a non-linear systematic error.
  • the steel wire rope may deform, depending on temperature and load, Yet another possibility is to use a string encoder in place of a rotary encoder.
  • MRUs motion reference units
  • VRUs vertical reference units
  • PID proportional-integral-derivative
  • a method includes receiving first information from a first sensor located on a drill floor of a marine drill. The method also includes receiving second information from a second sensor located on a top drive of the marine drill. The method further includes calculating a physical parameter based, in part, on the first information received from the first sensor and the second information received from the second sensor.
  • a computer program product includes a non-transitory computer readable medium having code to receive first information from a first sensor located on a drill floor of a marine drill.
  • the medium also includes code to receive second information from a second sensor located on a top drive of the marine drill.
  • the medium further includes code to calculate a physical parameter based, in part, on the first information received from the first sensor and the second information received from the second sensor.
  • an apparatus includes a first sensor located on a drill floor of a marine drill.
  • the apparatus also includes a second sensor located on a top drive of the marine drill.
  • the first sensor and the second sensor are set-up in a differential configuration.
  • the apparatus further includes a processor coupled to the first and second sensors. There is at least one processor configured to calculate a physical parameter based, in part, on the first information received from the first sensor and the second information received from the second sensor.
  • a second sensors may be installed on a marine drill, such as on a top block, to improve measurements used for monitoring and operating the marine drill
  • FIGURE 1 is a block diagram illustrating a marine drill with two sensors according to one embodiment of the disclosure.
  • a marine drill 100 such as a mobile offshore drilling unit (MODU) may include a drill floor 104.
  • a first sensor 114 may be located on the drill floor 104.
  • the first sensor 114 may include one or more of an accelerometer, a gyroscope, and a compass. According to one embodiment, the first sensor 114 may be appropriately rated for explosively hazardous areas.
  • the marine drill 100 may also include a top block 102.
  • a second sensor 112 may be located on the top block 102.
  • the second sensor 112 may include one or more of an accelerometer, a gyroscope, and a compass. According to one embodiment, the second sensor 112 is mounted on the top block 102.
  • the first sensor 114 and the second sensor 112 may be set-up in a differential configuration. For example, measurements may be taken from the first sensor 114 and the second sensor 112 nearly simultaneously, such that movement of the drill floor 104 detected by the first sensor 114 may be subtracted from the movement of the top block 102 detected by the second sensor 112.
  • the first sensor 114 and the second sensor 112 may be coupled to a processor (not yet shown) for calculating physical parameters of the marine drill 100.
  • FIGURE 2 is a block diagram illustrating a communication system for coupling two sensors on a marine drill according to one embodiment of the disclosure.
  • a processor 240 may receive information from a first sensor 214, such as a sensor located on a drill floor, through a communications bus 224.
  • the processor 240 may further communicate with the first sensor 214 through a command bus 234, such as a RS-232 or RS-422 serial bus.
  • the processor 240 may also receive information from a second sensor 212, such as a sensor located on a top block, through a communications bus 232.
  • a positioning data system 216 such as global positioning system (GPS) or global navigation satellite system (GNSS), may be coupled to the second sensor 212 to provide position information through a communications bus 222, such as a RS-232 or RS-422 serial bus.
  • the processor 240 may receive information from the first sensor 214 and the second sensor 212 such as, for example, heave, surge, and/or sway values. The processor 240 may then calculate physical parameters based on, in part, the information received from the first sensor 214 and the second sensor 212. The processor 240 may provide the calculated physical parameters to an external device (not shown) through a communications bus 242.
  • a time synchronization message and pulse may be provided to the first sensor 214 and the second sensor 212 to coordinate measurement by the two sensors 212 and 214.
  • FIGURE 3 is a flow chart illustrating a method for operating two sensors on a marine drill according to one embodiment of the disclosure.
  • a method 300 begins at block 302 with receiving first information from a first sensor on a drill floor of a marine drill.
  • the method 300 continues to block 304 to receive second information from a second sensor on a top drive of a marine drill.
  • the method 300 the continues to block 306 to calculate a physical parameter based, in part, on the first and second information received at blocks 302 and 304, respectively. Additional details of the calculation process are presented in FIGURES 4 and 5 .
  • FIGURE 4 is a block diagram illustrating mechanization of receiving information from two sensors on a marine drill according to one embodiment of the disclosure.
  • FIGURE 5 is a block diagram illustrating an atypical error state Kalman filter loop according to one embodiment of the disclosure.
  • the calculation at block 306 may include calculating a high definition rate of penetration (HDROP), HDROP refers to an accurate and precise pose estimation of the top drive and/or top block.
  • HDROP refers to an accurate and precise pose estimation of the top drive and/or top block.
  • the calculation of HDROP may use a proportional-integral-derivative (PID) loop and/or an optimal estimator such as an Error State Kalman Filter (ESKF).
  • ESKF Error State Kalman Filter
  • the results of the PID loop may be compared to the ESKF for a simple single state solution of noisy heave.
  • dynamic simulations may be used to emulate the observables based on known models.
  • calculations may start with true dynamics and then model the sensor outputs and additional errors to form new discretized data sets fed to the optimal estimator.
  • the current block position calculation may be based on configurations having a draw works rotary encoder on a jackup, having a draw works rotary encoder on a floating drilling platform (floater) with passive compensation and riser tensioners, having a draw works rotary encoder on a floater with active heave compensation.
  • the calculation at block 306 may include calculating a digital visualization of drilling level bubble.
  • the drilling level bubble may be displayed on a screen to provide a driller and/or a rig captain a visual indication of an ideal orientation for leveling, to reduce the likelihood binding of the tubular in the rotary table.
  • systemic errors such as angular offsets, may be removed during the calculation.
  • the calculation for a drilling level bubble may leverage inertial measurement unit (IMU) data, but may be performed without an error state Kalman filter and/or accurate time tagging.
  • IMU inertial measurement unit
  • the calculation at block 306 may include calculating an out-of-straightness (OOS) value.
  • OOS out-of-straightness
  • the information from the two sensors may be monitored to determine any mechanical binding of the top drive on the rails due to deformation as the top drive transitions from the rotary table to the crown.
  • a difference in orientation along the length of the rails may be calculated based on information from the two sensors. This difference may serve as a baseline measurement to compare with future measurements to determine if deformation of the rails has occurred.
  • An accurate instantaneous position of the top block may be calculated for OOS monitoring from an ESKF.
  • the calculation at block 306 may include condition-based monitoring.
  • Sensors such as accelerometers, placed on machinery on a marine drill may measure vibrations for that machinery.
  • Sensors on the top drive may measure a wide spectrum of components in the frequency domain, including low frequency vibrations due to vessel motion and high frequency vibrations due to motor operations.
  • the sensor inputs may be differentially combined to calculate the actual motion of the top drive.
  • vessel motion and drill floor vibrations may be removed or reduced from the top drives vibrations.
  • differential sensor configurations on a marine drill include seismic while drilling (SWD) and drill-break detection by determining bit movement and/or vibration returns, and fine motion control on the marine drill.
  • SWD seismic while drilling
  • drill-break detection by determining bit movement and/or vibration returns
  • fine motion control on the marine drill.
  • differential inertial sensors as described above improve the accuracy of measurements from a marine drill and improve the operation of the marine drill. For example, when differential sensors are placed on the top block and the drilling floor, measurements may be taken from the sensors and used to calculate a variety of physical parameters used in monitoring or operating the marine drill.
  • One application for a differential sensor configuration on a marine drill include precision motion control. Once an accurate spatial location of the block and the block's dynamics are known fine motion control applications may be implemented. This provides more accurate dynamic information than what is inferred by the rotary encoder.
  • FIGURE 6 illustrates a computer system 600 adapted according to certain embodiments as a server and/or a user interface device for processing and/or displaying data from the differential sensors of FIGURE 1 and FIGURE 2 .
  • the central processing unit (“CPU'') 602 is coupled to the system bus 604.
  • the CPU 602 may be a general purpose CPU or microprocessor, graphics processing unit (“GPU"), and/or microcontroller.
  • the present embodiments are not restricted by the architecture of the CPU 602 so long as the CPU 602, whether directly or indirectly, supports the modules and operations as described herein.
  • the CPU 602 may execute the various logical instructions according to the present embodiments, such as the method illustrated in FIGURE 3 .
  • the computer system 600 also may include random access memory (RAM) 608, which may be synchronous RAM (SRAM), dynamic RAM (DRAM), and/or synchronous dynamic RAM (SDRAM).
  • RAM random access memory
  • SRAM synchronous RAM
  • DRAM dynamic RAM
  • SDRAM synchronous dynamic RAM
  • the computer system 600 may utilize RAM 608 to store the various data structures used by a software application, such as information received from the first and second sensors.
  • the computer system 600 may also include read only memory (ROM) 606 which may be PROM, EPROM, EEPROM, optical storage, or the like.
  • ROM read only memory
  • the ROM may store configuration information for booting the computer system 600.
  • the RAM 608 and the ROM 606 hold user and system data.
  • the computer system 600 may also include an input/output (I/O) adapter 610, a communications adapter 614, a user interface adapter 616, and a display adapter 622.
  • the I/O adapter 610 and/or the user interface adapter 616 may, in certain embodiments, enable a user to interact with the computer system 600.
  • the display adapter 622 may display a graphical user interface (GUI) associated with a software or web-based application on a display device 624, such as a monitor or touch screen.
  • GUI graphical user interface
  • the I/O adapter 610 may couple one or more storage devices 612, such as one or more of a hard drive, a flash drive, a compact disc (CD) drive, a floppy disk drive, and a tape drive, to the computer system 600.
  • the communications adapter 614 may be adapted to couple the computer system 600 to a network, which may be one or more of a LAN, WAN, and/or the Internet.
  • the communications adapter 614 may also be adapted to couple the computer system 600 to other networks such as a global positioning system (GPS) or a Bluetooth network.
  • the user interface adapter 616 couples user input devices, such as a keyboard 620, a pointing device 618, and/or a touch screen (not shown) to the computer system 600.
  • the keyboard 620 may be an on-screen keyboard displayed on a touch panel. Additional devices (not shown) such as a camera, microphone, video camera, accelerometer, compass, and or a gyroscope may be coupled to the user interface adapter 616.
  • the display adapter 622 may be driven by the CPU 602 to control the display on the display device 624.
  • the application of the present disclosure are not limited to the architecture of computer system 600. Rather the computer system 600 is provided as an example of one type of computing device that may be adapted to perform the functions of a server and/or a user interface device.
  • any suitable processor-based device may be utilized including, without limitation, personal data assistants (PDAs), tablet computers, smartphones. computer game consoles, and multi-processor servers.
  • PDAs personal data assistants
  • the systems and methods of the present disclosure may be implemented on application specific integrated circuits (ASIC), very large scale integrated (VLSI) circuits, or other circuitry.
  • ASIC application specific integrated circuits
  • VLSI very large scale integrated circuits
  • persons of ordinary skill in the art may utilize any number of suitable structures capable of executing logical operations according to the described embodiments.
  • Computer-readable media includes physical computer storage media.
  • a storage medium may be any available medium that can be accessed by a computer.
  • such computer-readable media can comprise RAM, ROM, EEPROM, CD-ROM or other optical disk storage, magnetic disk storage or other magnetic storage devices, or any other medium that can be used to store desired program code in the form of instructions or data structures and that can be accessed by a computer; disk and disc, as used herein, includes compact disc (CD), laser disc, optical disc, digital versatile disc (DVD), floppy disk and blu-ray disc where disks usually reproduce data magnetically, while discs reproduce data optically with leasers. Combinations of the above should also be included within the scope of computer-readable media.
  • instructions and/or data may be provided as signals on transmission media included in a communication apparatus.
  • a communication apparatus may include a transceiver having signals indicative of instructions and data. The instructions and data are configured to cause one or more processors to implement the functions outlined in the claims.

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  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Geophysics (AREA)
  • Remote Sensing (AREA)
  • Earth Drilling (AREA)
  • Arrangements For Transmission Of Measured Signals (AREA)
  • Position Fixing By Use Of Radio Waves (AREA)
  • Length Measuring Devices With Unspecified Measuring Means (AREA)

Claims (14)

  1. Procédé, comprenant :
    la réception d'une première information d'un premier capteur situé sur un sol de forage d'un forage marin ;
    la réception d'une seconde information d'un second capteur situé sur un tête d'injection motorisée du forage marin ; et
    le calcul d'un paramètre physique sur la base, en partie, de la première information reçue du premier capteur et de la seconde information reçue du second capteur.
  2. Procédé selon la revendication 1, dans lequel le forage marin est une unité de forage offshore mobile.
  3. Procédé selon la revendication 1, comprenant en outre la génération d'une impulsion de synchronisation temporelle afin de coordonner une réception de la première information du premier capteur et une réception de la seconde information du second capteur.
  4. Procédé selon la revendication 1, dans lequel l'étape de calcul comprend le calcul d'un taux de pénétration pour le forage marin.
  5. Procédé selon la revendication 1, dans lequel l'étape de calcul comprend le calcul d'un niveau de forage pour le forage marin.
  6. Procédé selon la revendication 1, dans lequel l'étape de calcul comprend le calcul d'une valeur de déformation linéaire pour le forage marin.
  7. Procédé selon la revendication 1, dans lequel l'étape de calcul comprend le calcul d'un mouvement de vibration pour le forage marin.
  8. Procédé selon la revendication 1, dans lequel l'étape de calcul comprend le calcul d'un emplacement spatial et de la dynamique d'un bloc du forage marin.
  9. Programme informatique, comprenant :
    un support lisible sur ordinateur non transitoire comprenant :
    un code pour effectuer un procédé selon l'une quelconque des revendications 1 à 8.
  10. Appareil comprenant :
    un premier capteur situé sur un sol de forage d'un forage marin ;
    un second capteur situé sur une tête d'injection motorisée du forage marin, dans lequel le premier capteur et le second capteur sont paramétrés dans une configuration différentielle; et
    un processeur raccordé au premier capteur et au second capteur, dans lequel le au moins un processeur est configuré pour calculer un paramètre physique basé, en partie, sur la première information reçue du premier capteur et la seconde information reçue du second capteur.
  11. Appareil selon la revendication 10, dans lequel le processeur est en outre configuré pour calculer un taux de pénétration pour le forage marin.
  12. Appareil selon la revendication 10, dans lequel le processeur est en outre configuré pour calculer un niveau de forage pour le forage marin.
  13. Appareil selon la revendication 10, dans lequel le processeur est en outre configuré pour calculer une valeur de déformation linéaire pour le forage marin.
  14. Appareil selon la revendication 10, dans lequel le forage marine est une unité de forage offshore mobile.
EP13734149.1A 2012-01-23 2013-01-17 Taux de pénétration de forage de haute définition pour forage marin Not-in-force EP2807333B1 (fr)

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
US201261589445P 2012-01-23 2012-01-23
US13/741,990 US9217290B2 (en) 2012-01-23 2013-01-15 High definition drilling rate of penetration for marine drilling
PCT/IB2013/000763 WO2013121299A2 (fr) 2012-01-23 2013-01-17 Taux de pénétration de forage de haute définition pour forage marin

Publications (2)

Publication Number Publication Date
EP2807333A2 EP2807333A2 (fr) 2014-12-03
EP2807333B1 true EP2807333B1 (fr) 2016-11-02

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EP13734149.1A Not-in-force EP2807333B1 (fr) 2012-01-23 2013-01-17 Taux de pénétration de forage de haute définition pour forage marin

Country Status (14)

Country Link
EP (1) EP2807333B1 (fr)
JP (2) JP5930440B2 (fr)
KR (1) KR20140135689A (fr)
CN (1) CN104364467A (fr)
AP (1) AP2014007814A0 (fr)
AU (1) AU2013203035B2 (fr)
BR (1) BR112014018159A8 (fr)
CA (1) CA2861962C (fr)
EA (1) EA201400837A1 (fr)
IN (1) IN2014DN06133A (fr)
MX (1) MX360642B (fr)
NZ (1) NZ627706A (fr)
SG (1) SG11201404274TA (fr)
WO (1) WO2013121299A2 (fr)

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KR20190048101A (ko) 2017-10-30 2019-05-09 (주)일흥 모니터링이 가능한 용접 가이드 시스템
CN109820879A (zh) * 2018-11-14 2019-05-31 永腾生技有限公司 牛樟芝萃取物、牛樟芝组合物的制备方法及医药组合物
KR102294384B1 (ko) * 2020-12-31 2021-08-26 동아대학교 산학협력단 머신러닝을 이용한 굴진율 예측 시추운전가이드 모델 구축방법 및 이를 이용한 굴진율 예측시스템
CN113236233B (zh) * 2021-03-25 2022-10-14 西南石油大学 钻井牵引机器人位移测量装置

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MX360642B (es) 2018-11-12
JP2015504122A (ja) 2015-02-05
BR112014018159A2 (fr) 2017-06-20
CA2861962A1 (fr) 2013-08-22
AU2013203035B2 (en) 2015-06-11
NZ627706A (en) 2015-06-26
SG11201404274TA (en) 2014-08-28
EA201400837A1 (ru) 2014-11-28
AP2014007814A0 (en) 2014-07-31
WO2013121299A3 (fr) 2014-04-03
JP5930440B2 (ja) 2016-06-08
CA2861962C (fr) 2017-08-15
IN2014DN06133A (fr) 2015-08-14
WO2013121299A2 (fr) 2013-08-22
KR20140135689A (ko) 2014-11-26
BR112014018159A8 (pt) 2017-07-11
CN104364467A (zh) 2015-02-18
MX2014008937A (es) 2015-06-02
EP2807333A2 (fr) 2014-12-03
JP2016053302A (ja) 2016-04-14

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