Patent Application
20140011466
The application relates generally to communications. In particular, the application relates to a wireless communication in a drilling operations environment.
During drilling operations for extraction of hydrocarbons, a variety of communication and transmission techniques have been attempted to provide real time data from the vicinity of the bit to the surface during drilling. The use of measurements while drilling (MWD) with real time data transmission provides substantial benefits during a drilling operation. For example, monitoring of downhole conditions allows for an immediate response to potential well control problems and improves mud programs.
Measurement of parameters such as weight on bit, torque, wear and bearing condition in real time provides for more efficient drilling operations. In fact, faster penetration rates, better trip planning, reduced equipment failures, fewer delays for directional surveys, and the elimination of a need to interrupt drilling for abnormal pressure detection is achievable using MWD techniques.
Moreover, during a trip out operation, retrieval of data from the downhole tool typically requires a communications cable be connected thereto. The data rate for downloading data from the downhole tool over such cables is typically slow and requires physical contact with the tool. Additionally, a drilling rig operator must be present to connect a communications cable to the downhole tool to download data therefrom. The communications cable and connectors are often damaged by the harsh rig environment. Valuable rig time is often lost by normal cable handling as well as cable repairs. Furthermore, if the downhole tool includes a nuclear source the cable connection and data download cannot be initiated until such source is first safely removed.
Embodiments of the invention may be best understood by referring to the following description and accompanying drawings which illustrate such embodiments. The numbering scheme for the Figures included herein are such that the leading number for a given reference number in a Figure is associated with the number of the Figure. For example, a system 100 can be located in
Methods, apparatus and systems for a wireless communications in a drilling operations environment are described. In the following description, numerous specific details are set forth. However, it is understood that embodiments of the invention may be practiced without these specific details. In other instances, well-known circuits, structures and techniques have not been shown in detail in order not to obscure the understanding of this description.
While described in reference to wireless communications for drilling operations (such as Measurement While Drilling (MWD) or Logging While Drilling (LWD) drilling operations), embodiments of the invention are not so limited. For example, some embodiments may be used for communications during a logging operation using wireline tools.
Some embodiments include an instrument hub that is integrated into a drill string for drilling operations. The instrument hub may be located at or above the borehole. For example, the instrument hub may be located at or above the rig floor. The instrument hub may also include a bi-directional wireless antenna for communications with a remote ground station. In some embodiments, the instrument hub may include a number of sensors and actuators for communicating with instrumentation that is downhole. The instrument hub may also include a battery for powering the instrumentation within the instrument hub. Accordingly, some embodiments include an instrument hub integrated into the drill string, which does not require external wiring for power or communications. Therefore, some embodiments allow for communications with downhole instrumentation while drilling operations are continuing to occur. Moreover, some embodiments allow for wireless communications between the instrument hub and a remote ground station, while drilling operations continue. Therefore, the drill string may continue to rotate while these different communications are occurring. Furthermore, because the sensors and actuators within the instrument hub are integrated into the drill string, some embodiments allow for a better signal-to-noise ratio in comparison to other approaches.
Some embodiments include a downtool tool (that is part of the drill string) that includes an antenna for wireless communications with a remote ground station. The antenna may be separate from the other components in the downhole tool used to measure downhole parameters. In some embodiments, data stored in a machine-readable medium (e.g., a memory) in the downhole tool may be retrieved during a trip out operation after the antenna is in communication range of the remote ground station. Accordingly, the time of the trip out operation may be reduced because there is no need to physically connect a communication cable to the downhole tool prior to data transfer. Rather, the data transfer may commence after the antenna is in communication range of the remote ground station. Therefore, some embodiments reduce the loss of valuable drilling rig time associated with normal cable handling and repairs thereof.
During drilling operations, the drill string 108 (including the Kelly 116, the drill pipe 118 and the bottom hole assembly 120) may be rotated by the rotary table 110. In addition or alternative to such rotation, the bottom hole assembly 120 may also be rotated by a motor (not shown) that is downhole. The drill collar 122 may be used to add weight to the drill bit 126. The drill collar 122 also may stiffen the bottom hole assembly 120 to allow the bottom hole assembly 120 to transfer the weight to the drill bit 126. Accordingly, this weight provided by the drill collar 122 also assists the drill bit 126 in the penetration of the surface 104 and the subsurface formations 114.
During drilling operations, a mud pump 132 may pump drilling fluid (known as “drilling mud”) from a mud pit 134 through a hose 136 into the drill pipe 118 down to the drill bit 126. The drilling fluid can flow out from the drill bit 126 and return back to the surface through an annular area 140 between the drill pipe 118 and the sides of the borehole 112. The drilling fluid may then be returned to the mud pit 134, where such fluid is filtered. Accordingly, the drilling fluid can cool the drill bit 126 as well as provide for lubrication of the drill bit 126 during the drilling operation. Additionally, the drilling fluid removes the cuttings of the subsurface formations 114 created by the drill bit 126.
The drill string 108 (including the downhole tool 124) may include one to a number of different sensors 151, which monitor different downhole parameters. Such parameters may include the downhole temperature and pressure, the various characteristics of the subsurface formations (such as resistivity, density, porosity, etc.), the characteristics of the borehole (e.g., size, shape, etc.), etc. The drill string 108 may also include an acoustic transmitter 123 that transmits telemetry signals in the form of acoustic vibrations in the tubing wall of the drill sting 108. An instrument hub 115 is integrated into (part of the drill string 108) and coupled to the kelly 116. The instrument hub 115 is inline and functions as part of the drill pipe 118. In some embodiments, the instrument hub 115 may include transceivers for communications with downhole instrumentation. The instrument hub 115 may also includes a wireless antenna. The system 100 also includes a remote antenna 190 coupled to a remote ground station 192. The remote antenna 190 and/or the remote ground station 192 may or may not be positioned near or on the drilling rig floor. The remote ground station 192 may communicate wirelessly (194) using the remote antenna 190 with the instrument hub 115 using the wireless antenna. A more detailed description of the instrument hub 115 is set forth below.
Alternatively or in addition, communications between the instrument hub 115 and the downhole instrumentation may be based on mud pulse, acoustic communications, optical communications, etc. The instrument hub 115 may include sensors/gages 210. The sensors/gages 210 may include accelerometers to sense acoustic waves transmitted from downhole instrumentation. The accelerometers may also monitor low frequency drill string dynamics and sense generated bit noise traveling up the drill pipe. The sensors/gages 210 may include fluxgate sensors to detect magnetic fields that may be generated by instrumentation in the downhole tool 124. For example, the fluxgate sensors may be use to detect a magnetic field component of an electromagnetic field that may be representative of data communication being transmitted by instrumentation in the downhole tool 124. The sensors/gages 210 may include strain gages to monitor variations in applied torque and load. The strain gages may also monitor low frequency bending behavior of the drill pipe. In some embodiments, the sensors/gages 210 may include pressure gages to monitor mud flow pressure and to sense mud pulse telemetry pulses propagating through the annulus of the drill pipe. In some embodiments, the pressure gage reading in combination with the pressure reading on the standpipe may be processed by implementing sensor array processing techniques to increase signal to noise ratio of the mud pulses. The sensors/gages 210 may include acoustic or optical depth gages to monitor the length of the drill string 108 from the rig floor. In some embodiments, the sensors/gages 210 may include torque and load cells to monitor the weight-on-bit (WOB) and torque-on-bit (TOB). The sensors/gages 210 may include an induction coil for communications through wired pipe. The sensors/gages 210 may include an optical transceiver for communication through optical fiber from downhole.
The sensors/gages 210 may be coupled to the encoder 208. The encoder 208 may provide signal conditioning, analog-to-digital (A-to-D) conversion and encoding. For example, the encoder 208 may receive the data from the sensors/gages 210 and condition the signal. The encoder 208 may digitize and encode the conditioned signal. The sensors/gages 210 may be coupled to a transmitter 206. The transmitter 206 may be coupled to the antenna 204. In some embodiments, the antenna 204 comprises a 360° wraparound antenna. Such configurations allow the wireless transmission and reception to be directionally insensitive by providing a uniform transmission field transverse to the drill string 108.
The antenna 204 may also be coupled to a receiver 212. The receiver 212 is coupled to a decoder 214. The decoder 214 may be coupled to the downlink driver 216. The downlink driver 216 may be coupled to the downlink transmitter 218. The downlink transmitter 218 may include components to generate acoustic signals, mud pulse signals, electrical signals, optical signals, etc. for transmission of data to downhole instrumentation. For example, the downlink transmitter 218 may include a piezoelectric stack for generating an acoustic signal. The downlink transmitter 218 may include an electromechanical valve mechanism (such as an electromechanical actuator) for generating mud pulse telemetry signals. In some embodiments, the downlink transmitter 218 may include instrumentation for generating electrical signals that are transmitted through the wire of the wired pipe. The downlink transmitter 218 may also include instrumentation for generating optical signals that are transmitted through the optical cables that may be within the drill string 108.
In some embodiments, the instrument hub 115 may also include a battery 218 that is coupled to a DC (Direct Current) converter 220. The DC converter 220 may be coupled to the different components in the instrument hub 115 to supply power to these components.
A more detailed description of some embodiments of the operations of the instrument hub 115 is now described. In particular,
In block 402, a first signal is received from instrumentation that is downhole into an instrument hub that is integrated into a drill string. With reference to the embodiments of
In block 404, the first signal is wirelessly transmitted, using an antenna that is wrapped around the instrument hub, to a remote data processor unit. With reference to the embodiments of
For example, communication between the instrument hub 115 and the remote ground station 192 may be formatted according to CDMA (Code Division Multiple Access) 2000 and WCDMA (Wideband CDMA) standards, a TDMA (Time Division Multiple Access) standard and a FDMA (Frequency Division Multiple Access) standard. The communication may also be formatted according to an Institute of Electrical and Electronics Engineers (IEEE) 802.11, 802.16, or 802.20 standard.
For more information regarding various IEEE 802.11 standards, please refer to “IEEE Standards for Information Technology—Telecommunications and Information Exchange between Systems—Local and Metropolitan Area Network—Specific Requirements—Part 11: Wireless LAN Medium Access Control (MAC) and Physical Layer (PHY), ISO/IEC 8802-11: 1999” and related amendments. For more information regarding IEEE 802.16 standards, please refer to “IEEE Standard for Local and Metropolitan Area Networks—Part 16: Air Interface for Fixed Broadband Wireless Access Systems, IEEE 802.16-2001”, as well as related amendments and standards, including “Medium Access Control Modifications and Additional Physical Layer Specifications for 2-11 GHz, IEEE 802.16a-2003”. For more information regarding IEEE 802.20 standards, please refer to “IEEE Standard for Local and Metropolitan Area Networks—Part 20: Standard Air Interface for Mobile Broadband Wireless Access Systems Supporting Vehicular Mobility—Physical and Media Access Control Layer Specification, IEEE 802.20 PD-02, 2002”, as well as related amendments and documents, including “Mobile Broadband Wireless Access Systems Access Systems “Five Criteria” Vehicular Mobility, IEEE 802.20 PD-03, 2002.
For more information regarding WCDMA standards, please refer to the various 3rd Generation Partnership Project (3GPP) specifications, including “IMT-2000 DS-CDMA System,” ARIB STD-T63 Ver. 1.4303.100 (Draft), Association of Radio Industries and Businesses (ARIB), 2002. For more information regarding CDMA 2000 standards, please refer to the various 3rd Generation Partnership Project 2 (3GPP2) specifications, including “Physical Layer Standard for CDMA2000 Spread Spectrum Systems,” 3GPP2 C.S0002-D, Ver. 1.0, Rev. D, 2004.
The communication between the instrument hub 115 and the remote ground station 192 may be based on a number of different spread spectrum techniques. The spread spectrum techniques may include frequency hopping spread spectrum (FHSS), direct sequence spread spectrum (DSSS), orthogonal frequency domain multiplexing (OFDM), or multiple-in multiple-out (MIMO) specifications (i.e., multiple antenna), for example.
The transmitter 206 may receive the encoded signal from the encoder 208 and wirelessly transmit the encoded signal through the antenna 204 to the remote ground station 192. Control continues at block 406.
In block 406, a second signal is wirelessly received using the antenna that is wrapped around the instrument hub 115 from the remote data processor unit. With reference to the embodiments of
In block 408, the second signal is transmitted to the instrumentation downhole. With reference to the embodiments of
While the operations of the flow diagram 400 are shown in a given order, embodiments are not so limited. For example, the operations may be performed simultaneously in part or in a different order. As described, there is no requirement to stop the drilling operations (including the rotation of the drill string 108) while the operations of the flow diagram 400 are being performed. Accordingly, embodiments may allow for the drilling operations to be performed more quickly and accurately.
The downhole tool 124 includes an antenna 502 and a sensor 504. The sensor 504 may be representative of one to a number of sensors that may measure a number of different parameters, such as the downhole temperature and pressure, the various characteristics of the subsurface formations (such as resistivity, density, porosity, etc.), the characteristics of the borehole (e.g., size, shape, etc.), etc. The antenna 502 may be used for wireless communications with the remote ground station 192 (shown in
Communication between the antenna 502 on the downhole tool 124 and the remote ground station 192 may be formatted according to CDMA (Code Division Multiple Access) 2000 and WCDMA (Wideband CDMA) standards, a TDMA (Time Division Multiple Access) standard and a FDMA (Frequency Division Multiple Access) standard. The communication may also be formatted according to an Institute of Electrical and Electronics Engineers (IEEE) 802.11, 802.16, or 802.20 standard. The communication between the antenna 502 and the remote ground station 192 may be based on a number of different spread spectrum techniques. The spread spectrum techniques may include frequency hopping spread spectrum (FHSS), direct sequence spread spectrum (DSSS), orthogonal frequency domain multiplexing (OFDM), or multiple-in multiple-out (MIMO) specifications (i.e., multiple antenna), for example.
A more detailed description of some embodiments of the operations of the downhole tool 124 is now described. In particular,
In block 602 of a flow diagram 600, a downhole parameter is measured, using a sensor in a downhole tool of a drill string, while the downhole tool is below the surface. With reference to the embodiments of
In block 604, the downhole parameter is transmitted wirelessly, using an antenna in the downhole tool, to a remote ground station, during a trip out operation of the drill string and after the downhole tool is approximately at or near the surface. With reference to the embodiments of
In the description, numerous specific details such as logic implementations, opcodes, means to specify operands, resource partitioning/sharing/duplication implementations, types and interrelationships of system components, and logic partitioning/integration choices are set forth in order to provide a more thorough understanding of the present invention. It will be appreciated, however, by one skilled in the art that embodiments of the invention may be practiced without such specific details. In other instances, control structures, gate level circuits and full software instruction sequences have not been shown in detail in order not to obscure the embodiments of the invention. Those of ordinary skill in the art, with the included descriptions will be able to implement appropriate functionality without undue experimentation.
References in the specification to “one embodiment”, “an embodiment”, “an example embodiment”, etc., indicate that the embodiment described may include a particular feature, structure, or characteristic, but every embodiment may not necessarily include the particular feature, structure, or characteristic. Moreover, such phrases are not necessarily referring to the same embodiment. Further, when a particular feature, structure, or characteristic is described in connection with an embodiment, it is submitted that it is within the knowledge of one skilled in the art to affect such feature, structure, or characteristic in connection with other embodiments whether or not explicitly described.
A number of figures show block diagrams of systems and apparatus for wireless communications in a drilling operations environment, in accordance with some embodiments of the invention. A number of figures show flow diagrams illustrating operations for wireless communications in a drilling operations environment, in accordance with some embodiments of the invention. The operations of the flow diagrams are described with references to the systems/apparatus shown in the block diagrams. However, it should be understood that the operations of the flow diagrams could be performed by embodiments of systems and apparatus other than those discussed with reference to the block diagrams, and embodiments discussed with reference to the systems/apparatus could perform operations different than those discussed with reference to the flow diagrams.
In view of the wide variety of permutations to the embodiments described herein, this detailed description is intended to be illustrative only, and should not be taken as limiting the scope of the invention. What is claimed as the invention, therefore, is all such modifications as may come within the scope and spirit of the following claims and equivalents thereto. Therefore, the specification and drawings are to be regarded in an illustrative rather than a restrictive sense.
The application is a continuation of U.S. application Ser. No. 11/098,893, filed 5 Apr. 2005, which application claims the benefit of priority under 35 U.S.C. §119(e) to U.S. Provisional Patent Application Ser. No. 60/584,732, filed 1 Jul. 2004, which applications are incorporated herein by reference in their entirety.
| Number | Date | Country | |
|---|---|---|---|
| 60584732 | Jul 2004 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 11098893 | Apr 2005 | US |
| Child | 14018159 | US |
