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
  • 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
  • E21B47/14—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 using acoustic waves
  • E21B47/18—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 using acoustic waves through the well fluid, e.g. mud pressure pulse telemetry
• • 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
  • E21B47/13—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 by electromagnetic energy, e.g. radio frequency
• • 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
  • E21B47/14—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 using acoustic waves
  • E21B47/16—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 using acoustic waves through the drill string or casing, e.g. by torsional acoustic waves

Definitions

• the present invention relates generally to telemetry apparatuses and methods, and more particularly to acoustic telemetry relay network timing for exploration, completion and production wells for hydrocarbons and other resources, and for other telemetry applications.
• Acoustic telemetry is a method of communication used in the well drilling, completion and production industries.
• acoustic extensional carrier waves from an acoustic telemetry device are modulated in order to carry information via the drillpipe as the transmission medium to the surface.
• the waves Upon arrival at the surface, the waves are detected, decoded and displayed in order that drillers, geologists and others helping steer or control the well are provided with drilling and formation data.
• downhole information can similarly be transmitted via the well casings.
• Acoustic telemetry transmits data to the surface in real-time and is independent of fluid flow, depth, well trajectory and other drilling parameters.
• an acoustic transmitter is preferentially placed near the BHA, typically near the drill bit where the transmitter can gather certain drilling and geological formation data, process this data, and then convert the data into a signal to be transmitted up-hole to an appropriate receiving and decoding node.
• the transmitter is designed to produce elastic extensional stress waves that propagate through the drillstring to the surface, where the waves are detected by sensors, such as accelerometers, attached to the drill string or associated drilling rig equipment. These waves carry information of value to the drillers and others who are responsible for steering the well. Examples of such systems and their components are shown in: Drumheller U.S. Patent No. 5,128,901 for Acoustic Data
• nodes are defined as receivers (Rx), transmitters or transceivers (Tx) for telemetry signals traveling between adjacent pairs of nodes.
• the nodes could be associated with and referred to as "stations" (e.g., ST0, ST1, ... STn) located along the drillstring.
• stations e.g., ST0, ST1, ... STn
• the low data rate linear repeater networks suffer from high latency (time for data to propagate through the network) due to the time it takes for each node to receive data packets and relay data onward.
• An objective of repeater networks is to relay data as quickly as possible after initial receipt, in order to minimize latency of data delivered to the surface (or other destination) and to maximize data throughput.
• a possible solution to drillstring acoustic communication latency-associated problems is to include time-of-measurement information with transmitted information from each node.
• time-of-measurement e.g., sensor acquisition time
• bandwidth limitations make the inclusion of time-of-measurement (e.g., sensor acquisition time) information overhead in the acoustic packets undesirable, and require all downhole clocks to be very accurately aligned, which can be problematic given the significant temperature differentials across the networks (e.g., 150° C or more) and the long periods of continuous network operation.
• a repeater network is provided with highly controlled and predictable timing. This is achieved by reconfiguring the network with constants, which are known to all nodes: guard time, allocated time between receipt and transmission (relay), thus allowing for processing time, acquisition of sensor data and subsiding of channel delay spread (echoes, e.g., 0.5-5 seconds); and data packet transmission time, a function of the internode data rate and the packet bit length (for example, a 100-bit packet transmitted at a 20 bits-per-second (bps) link rate would have a data packet transmission time of 5 seconds).
• the sensor acquisition time is typically negligible, and is determined by the time between the acquisition of a measurement from a sensor to transmission of the corresponding data through the telemetry network.
• a surface time-of-measurement for the relative timing offsets of all relay transmissions within the network can be computed from variables including: the packet received times, packet types, and guard and sensor acquisition times. Propagation delays can either be neglected or included in the time-of-measurement computation based on node separations and depth from surface, i.e., node depths.
• the advantages of the repeater network timing control include, without limitation:
• timing can change from frame-to-frame (packet type-to- packet type).
• FIG. 1 is a diagram of a typical drilling rig, including an acoustic telemetry system, which can be provided with a downhole linear repeater relay network timing system embodying an aspect of the present invention.
• FIG. 2 is a fragmentary, side-elevational and cross-sectional view of a typical drillstring, which can provide the medium for acoustic telemetry transmissions for relaying, repeating and timing with the present invention.
• FIG. 3 is a schematic diagram of the repeater relay network timing system of the present invention, particularly showing accurate surface time-of-measurement.
• FIG. 4 is another schematic diagram of the repeater relay network timing system, particularly showing how a surface decode time-of-receipt of telemetry signal can be related back to the sensor acquisition time of any network node.
• FIG. 5 is another schematic diagram of the repeater relay network timing system, particularly showing how a surface decode time-of-receipt of telemetry signal of a packet containing synchronized data is related to synchronized sensor acquisition across the network.
• the reference numeral 2 generally designates a downhole low rate linear repeater relay network timing or control system embodying an aspect of the present invention.
• a drilling rig 4 FIG. 1
• the rig 4 can include a derrick 6 suspending a traveling block 8 mounting a kelly swivel 10, which receives drilling mud via a kelly hose 1 1 for pumping downhole into a drillstring 12.
• the drillstring 12 is rotated by a kelly spinner 14 connected to a kelly pipe 16, which in turn connects to multiple drill pipe sections 18, which are interconnected by tool joints 19, thus forming a drillstring of considerable length, e.g., several kilometers, which can be guided downwardly and/or laterally using well-known techniques.
• the drillstring 12 terminates at a bottom-hole assembly (BHA) 20 at acoustic transceiver node (ST0).
• BHA bottom-hole assembly
• ST0 acoustic transceiver node
• Other rig configurations can likewise employ the present invention, including top-drive, coiled tubing, etc.
• additional applications include completion rigs, completion strings, casing strings, gravel packs, frac packs and other applications.
• acoustic telemetry systems in general can utilize the repeater network timing control system and method of the present invention.
• FIG. 1 also shows the components of the drillstring 12 just above the BHA 20, which can include, without limitation, a repeater transceiver node 26 STl and an additional repeater transceiver node 22, ST2.
• An upper, adjacent drillpipe section 18a is connected to the repeater 22 and the transmitter 26.
• a downhole adjacent drillpipe section 18b is connected to the transmitter 26 and the BHA 20.
• a surface receiver (node) 21 can be provided at or near the upper end of the drillstring 12.
• FIG. 2 shows the internal construction of the drillstring 12, e.g., an inner drillpipe 30 within an outer casing 32. Interfaces 28a, 28b are provided for connecting drillpipe sections to each other and to the other drillpipe components, as described above.
• W.1 illustrates an acoustic, electromagnetic or other energy waveform transmitted along the drillstring 12, either upwardly or downwardly.
• the drillstring 12 can include multiple additional repeaters 22 at intervals determined by operating parameters such as optimizing signal transmissions with minimal delays and errors.
• the drillstring 12 can also include multiple sensors along its length for producing output signals corresponding to various downhole conditions.
• FIG. 3 shows the operation of a downhole low rate linear repeater acoustic network timing control system.
• Other applications of the present invention include electromagnetic signal telemetry systems and systems transmitting signals through other media, such as drilling mud, ground, water, air, etc.
• Telemetry data packets contain sensor or tool status data and are transmitted from the primary node (ST0, typically the deepest node) and relayed from node-to-node to the surface receiver 21 (Surface Rx), which is generally located at or near the wellhead.
• the telemetry data packets include sensor measurements from the BHA 20 and other sensors along the drillstring 12.
• Such data packet sensor measurements can include, without limitation, wellbore conditions (e.g., annular/bore/differential pressure, fluid flow, vibration, rotation, etc.).
• Local sensor data can be added to the data packet being relayed at each sensor node, thus providing along-string-measurements (ASMs).
• ASMs along-string-measurements
• a single node functions as the master node (e.g., ST0) and is typically an edge node at the top or bottom of the drillstring 12.
• the master node monitors well conditions and sends data packets of varying types and intervals accordingly.
• the asynchronous nature of wellbore variation tends to cause latency in an ASM operating mode because data-receiving nodes must await incoming packets before determining what sensor measurements must be acquired for inclusion in the packets being relayed.
• Such latency in a low-throughput repeater network translates into a potentially large time difference between the point when a downhole sensor measurement is made and when that value is delivered to the surface.
• time-of-measurement i.e., telemetry signal receive time
• additional problems can arise based on prohibitively large bandwidth requirements necessitated by the network low data rates, and the necessity of highly accurate alignment (synchronization) of downhole and surface clocks, which can be problematic due to relatively wide temperature differentials across the network (e.g., 150° C +), and long periods of network operation.
• all time constraints are controlled based on pre-configured constants, which are input to all nodes.
• the pre-configured constants can include: ⁇ Guard Times: time allocated between receipt and transmission (relay) to allow for processing time, acquisition of sensor data and channel delay spread (echoes) subsiding. Typically about 0.5 to 5.0 seconds.
• Packet Transmission Time a function of the internode data rate and packet bit length.
• the surface receiver can calculate the relative timing offsets of all relay transmissions within the network based on the telemetry signal received time (e.g., time-of-measurement) of any packet and its type. With the additional information of sensor acquisition time, an exact time of sensor measurement can be calculated from the received time and used as an accurate time-of-measurement as follows: N : Decoded Packet STID
• all nodes In cases requiring quality differential measurements between nodes, all nodes must acquire sensor measurement data at the same point in time, and add the data to the appropriate relay packet such that the packet delivered to the surface contains time- synchronized sensor data acquisition. This can be accomplished with controlled network timing, if, based upon receipt time and type of a packet, all nodes can calculate the relative point in time at which the primary node (e.g. ST0, deepest node) acquired its measurement data, and acquire sensor data at that same point in time.
• the primary node e.g. ST0, deepest node
• the primary node sensor acquisition point occurred in the past. Sensor acquisition must therefore occur regularly and be buffered such that past measurement values are accessible. Buffer capacity and sampling rate are determined by the greatest possible frame length of all configurable modes, and the required alignment accuracy in the data of the network synchronized measurement.
• the packets that are configured with network synchronized payload data will have their times-of-measurement adjusted according to that of the primary node.
• all nodes acquire sensor measurement value at the same point in time as the primary node. All nodes have the same acquisition time.
• a surface decode time-of-receipt of telemetry signal can be related back to the sensor acquisition time of STO, as shown in FIG. 5.
• the network synchronized sensor acquisition could be aligned with any node within the network, or any point in time within a frame.

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• Engineering & Computer Science (AREA)
• Physics & Mathematics (AREA)
• Life Sciences & Earth Sciences (AREA)
• Mining & Mineral Resources (AREA)
• Geology (AREA)
• Remote Sensing (AREA)
• Environmental & Geological Engineering (AREA)
• Fluid Mechanics (AREA)
• Geophysics (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Geochemistry & Mineralogy (AREA)
• Acoustics & Sound (AREA)
• Electromagnetism (AREA)
• Arrangements For Transmission Of Measured Signals (AREA)
• Synchronisation In Digital Transmission Systems (AREA)

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• 2014
  • 2014-03-06 EP EP14884471.5A patent/EP3114317B1/de active Active
  • 2014-03-06 WO PCT/US2014/021356 patent/WO2015134030A1/en active Application Filing
  • 2014-03-06 BR BR112016020523A patent/BR112016020523A2/pt not_active IP Right Cessation
  • 2014-03-06 CA CA2941558A patent/CA2941558C/en active Active

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