EP3114317B1 - Système et procédé de synchronisation de réseau relais de répéteurs linéaires à faible débit de fond de puits - Google Patents
Système et procédé de synchronisation de réseau relais de répéteurs linéaires à faible débit de fond de puits Download PDFInfo
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- EP3114317B1 EP3114317B1 EP14884471.5A EP14884471A EP3114317B1 EP 3114317 B1 EP3114317 B1 EP 3114317B1 EP 14884471 A EP14884471 A EP 14884471A EP 3114317 B1 EP3114317 B1 EP 3114317B1
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- 238000005259 measurement Methods 0.000 claims description 39
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Images
Classifications
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- 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
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- 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
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- 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 When exploring for oil or gas, in coal mine drilling and in other drilling applications, 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.
- 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.
- the latency of delivered measurement data translates into a potentially large time difference between the time at which a downhole sensor measurement is made and when that value is delivered to the surface, obscuring potentially valuable correlation between downhole and uphole events. Additionally, as sensor acquisition at each node within the network occurs at different points in time, the accuracy of inter-node differential measurements is limited, impairing the ability to discern transient events traversing the string.
- 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.
- US 2010/0097890 A1 discloses methods and apparatuses for data collection and communication in drill string components
- US 2010/0313646 A1 discloses a system and method for associating time stamped measurement data with a corresponding wellbore depth
- US 2012/274477 A1 discloses a reliable downhole data transmission system.
- the advantages of the repeater network timing control may include, without limitation:
- 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 11 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 ST1 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 drill string 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:
- 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.
- the telemetry signal received time e.g., time-of-measurement
- an exact time of sensor measurement can be calculated from the received time and used as an accurate time-of-measurement as follows:
- propagation delay node depth x group velocity.
- 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 ST0, as shown in FIG. 5 .
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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)
- Acoustics & Sound (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Electromagnetism (AREA)
- Arrangements For Transmission Of Measured Signals (AREA)
- Synchronisation In Digital Transmission Systems (AREA)
Claims (11)
- Procédé de commande de synchronisation de relais pour un réseau répéteur linéaire à faible débit de fond de trou pour un appareil de forage (4) comprenant un train de tiges de forage (12) s'étendant souterrain vers le bas depuis une tête de puits de surface, un noeud (STO) situé près d'une extrémité de train de tiges de forage et incluant un capteur adapté pour fournir une sortie d'ensemble de données de signal correspondant à des conditions de fond de trou, et de multiples noeuds (ST) situés en fond de trou entre ledit noeud (STO) et ladite tête de puits et associés audit train de tiges de forage, lesdits noeuds (ST) étant configurés pour recevoir et retransmettre lesdits signaux, le procédé comprenant les étapes consistant à :
commander et spécifier des constantes de synchronisation de réseau incluant :des temps de transmission de paquet en fonction du débit de données internodal et de la longueur en bits de paquet ;des temps de garde alloués entre la réception et la transmission pour permettre le temps de traitement, l'acquisition des données de capteur et l'affaissement de l'étalement de retard de canal ;des temps de propagation de signaux entre les noeuds en fonction de la séparation de noeuds ; etdes temps d'acquisition de capteur intra-noeud ;déterminer des décalages de synchronisation de noeuds par rapport à des noeuds de réseau (ST, STO) sur la base d'un temps de réception d'un paquet de données de télémétrie provenant d'un autre noeud (ST, STO), du type de paquet reçu, et des constantes de synchronisation de réseau ; etutiliser lesdits décalages de synchronisation de noeuds pour définir une synchronisation de noeuds (ST, STO). - Procédé de commande de synchronisation selon la revendication 1, qui inclut les étapes supplémentaires consistant à :
déterminer un moment pour l'acquisition de mesure de capteur sur la base desdits décalages de synchronisation et desdites constantes de synchronisation de réseau. - Procédé de commande de synchronisation selon la revendication 2, qui inclut les étapes supplémentaires consistant à :
dériver un moment d'acquisition de données de mesure de capteur contenues dans un paquet reçu, sur la base dudit temps de réception de paquet de données et desdites constantes de synchronisation de réseau. - Procédé de commande de synchronisation selon la revendication 1, qui inclut les étapes supplémentaires consistant à :acquérir, par le biais desdits noeuds, des données de mesure de capteur correspondant à un moment aligné avec le temps d'acquisition de données de mesure d'un autre noeud ;mettre en mémoire tampon des mesures de capteur des mesures de capteur pour permettre l'accès aux données de capteur passées ; etconfigurer ledit réseau pour contenir des données de mesure de multiples noeuds correspondant audit même moment d'acquisition dans un seul paquet de données.
- Procédé de commande de synchronisation selon la revendication 1, qui inclut l'étape supplémentaire consistant à :
prendre en charge de multiples modes de synchronisation de réseau, correspondant à différents ensembles de constantes de synchronisation de réseau. - Procédé de commande de synchronisation selon la revendication 1, qui inclut l'étape supplémentaire consistant à sélectionner le procédé de transmission par télémétrie en mode réseau dans le groupe comprenant des réseaux acoustiques, d'impulsions électromagnétiques, d'impulsions dans la boue et filaires.
- Système de synchronisation de réseau relais répéteur linéaire à faible débit de fond de trou (2) pour un appareil de forage (4) incluant un train de tiges de forage (12) s'étendant souterrain vers le bas depuis une tête de puits de surface, lequel système inclut :un noeud (STO) situé près d'une extrémité de train de tiges de forage et incluant un capteur adapté pour fournir une sortie d'ensemble de données de signal correspondant à des conditions de fond de trou ;de multiples noeuds (ST) situés en fond de trou entre ledit noeud (STO) et ladite tête de puits et associés audit train de tiges de forage, lesdits noeuds (ST) recevant et retransmettant lesdits signaux ; etledit système de synchronisation de réseau relais étant adapté pour commander tous les temps dans une trame selon des constantes préconfigurées connues de tous les noeuds (ST, STO) lesdites constantes préconfigurées incluant : des temps de garde alloués entre la réception et la transmission pour permettre le temps de traitement, l'acquisition des données de capteur et l'affaissement de l'étalement de retard de canal ; un temps de transmission de paquet en fonction du débit de données internodal et de la longueur en bits de paquet ; un temps de propagation de signaux entre les noeuds en fonction de la séparation de noeuds ; et des temps d'acquisition de capteur intra-noeud ;dans lequel le système de synchronisation de réseau relais est configuré pour dériver des décalages de synchronisation pour lesdits noeuds les uns par rapport aux autres sur la base d'un temps de réception d'un paquet de données de télémétrie provenant d'un autre noeud (ST, STO), du type de paquet reçu, et des constantes préconfigurées.
- Système de synchronisation de réseau relais selon la revendication 7, qui inclut :
le système de synchronisation de réseau relais appliqué au niveau d'une surface calculant les décalages de synchronisation relatifs de toutes les transmissions de relais dans le réseau sur la base du moment de réception de signal de télémétrie de tout paquet et de son type. - Système de synchronisation de réseau relais selon la revendication 7, qui inclut des mesures de capteur de noeud mises en mémoire tampon dans le temps.
- Système de synchronisation de réseau relais selon la revendication 7, dans lequel ledit chaque noeud sélectionne une mesure passée mise en mémoire tampon pour l'alignement avec un moment de mesure de noeud de référence prédéfini.
- Système de synchronisation de réseau relais selon la revendication 7, dans lequel un noeud de surface calcule les décalages de synchronisation relatifs de toutes les transmissions de relais dans le réseau sur la base du moment de signal de télémétrie reçu d'un paquet de données de télémétrie et du type d'un noeud quelconque.
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
PCT/US2014/021356 WO2015134030A1 (fr) | 2014-03-06 | 2014-03-06 | Système et procédé de synchronisation de réseau relais de répéteurs linéaires à faible débit de fond de puits |
Publications (3)
Publication Number | Publication Date |
---|---|
EP3114317A1 EP3114317A1 (fr) | 2017-01-11 |
EP3114317A4 EP3114317A4 (fr) | 2017-11-01 |
EP3114317B1 true EP3114317B1 (fr) | 2023-04-26 |
Family
ID=54055689
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
EP14884471.5A Active EP3114317B1 (fr) | 2014-03-06 | 2014-03-06 | Système et procédé de synchronisation de réseau relais de répéteurs linéaires à faible débit de fond de puits |
Country Status (4)
Country | Link |
---|---|
EP (1) | EP3114317B1 (fr) |
BR (1) | BR112016020523A2 (fr) |
CA (1) | CA2941558C (fr) |
WO (1) | WO2015134030A1 (fr) |
Citations (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
EP2972527B1 (fr) * | 2013-03-15 | 2019-10-23 | Baker Hughes Oilfield Operations LLC | Système et procédé de télémesure de réseau |
Family Cites Families (6)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US7765422B2 (en) * | 2001-01-19 | 2010-07-27 | Alcatel-Lucent Usa Inc. | Method of determining a time offset estimate between a central node and a secondary node |
US7139218B2 (en) * | 2003-08-13 | 2006-11-21 | Intelliserv, Inc. | Distributed downhole drilling network |
JP4714025B2 (ja) * | 2006-01-06 | 2011-06-29 | 株式会社日立製作所 | センサノード、基地局、センサネット及びセンシングデータの送信方法 |
US8242928B2 (en) * | 2008-05-23 | 2012-08-14 | Martin Scientific Llc | Reliable downhole data transmission system |
US8164980B2 (en) | 2008-10-20 | 2012-04-24 | Baker Hughes Incorporated | Methods and apparatuses for data collection and communication in drill string components |
US8731837B2 (en) * | 2009-06-11 | 2014-05-20 | Schlumberger Technology Corporation | System and method for associating time stamped measurement data with a corresponding wellbore depth |
-
2014
- 2014-03-06 WO PCT/US2014/021356 patent/WO2015134030A1/fr active Application Filing
- 2014-03-06 CA CA2941558A patent/CA2941558C/fr active Active
- 2014-03-06 BR BR112016020523A patent/BR112016020523A2/pt not_active IP Right Cessation
- 2014-03-06 EP EP14884471.5A patent/EP3114317B1/fr active Active
Patent Citations (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
EP2972527B1 (fr) * | 2013-03-15 | 2019-10-23 | Baker Hughes Oilfield Operations LLC | Système et procédé de télémesure de réseau |
Also Published As
Publication number | Publication date |
---|---|
EP3114317A4 (fr) | 2017-11-01 |
CA2941558A1 (fr) | 2015-09-11 |
BR112016020523A2 (pt) | 2017-10-03 |
WO2015134030A1 (fr) | 2015-09-11 |
EP3114317A1 (fr) | 2017-01-11 |
CA2941558C (fr) | 2023-10-10 |
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