EP0314654B1 - Dispositif et procédé pour transmettre des données à la surface à partir d'un puits de pétrole - Google Patents

Dispositif et procédé pour transmettre des données à la surface à partir d'un puits de pétrole Download PDF

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Publication number
EP0314654B1
EP0314654B1 EP88850358A EP88850358A EP0314654B1 EP 0314654 B1 EP0314654 B1 EP 0314654B1 EP 88850358 A EP88850358 A EP 88850358A EP 88850358 A EP88850358 A EP 88850358A EP 0314654 B1 EP0314654 B1 EP 0314654B1
Authority
EP
European Patent Office
Prior art keywords
transmitter
receiving unit
casing
unit
signals
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.)
Expired - Lifetime
Application number
EP88850358A
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German (de)
English (en)
Other versions
EP0314654A1 (fr
Inventor
Truls Fallet
Havard Garseth
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.)
Saga Petroleum AS
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Saga Petroleum AS
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Filing date
Publication date
Application filed by Saga Petroleum AS filed Critical Saga Petroleum AS
Publication of EP0314654A1 publication Critical patent/EP0314654A1/fr
Application granted granted Critical
Publication of EP0314654B1 publication Critical patent/EP0314654B1/fr
Anticipated expiration legal-status Critical
Expired - Lifetime 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
    • 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

Definitions

  • the present invention relates to a method for transmitting data to the surface from a level in an oil well and an apparatus for carrying out the method, all according to the preamble of the claims.
  • the present invention provides a method and an apparatus overcoming the above mentioned problem, i.e. transferring data from a level in an oil well to the surface. This is obtained by a method and an apparatus according to the present invention, as defined by the features indicated in the characterizing clauses of the claims.
  • the present invention is based on the use of casings as a line of transmission.
  • the principle is based on the fact that a tubular electrical conductor through a homogenous continuous medium with a specific conductivity, will have a specific resistance, internal inductivity and conductivity in relation to the environments.
  • the conductor is the central conductor in a coaxial transmission line, the characteristic impedance and attenuation can be calculated.
  • Minimum loss of signal is obtained by adapting the impedance between the transmitter and the characteristic impedance of the transmission line.
  • the receiver is alined to the impedance of the transmission line. Depending on the configuration of the well and thus the impedance at the point of the receiver, it is possible to measure current or voltage and the corresponding alignment of the input stage of the receiver.
  • the attenuation of the signal along the line is greatly dependent from the specific resistivity of the materials being arranged close to the conductor.
  • the quality of the cement used for a casting of the casing in the drill bore is therefore of great importance to the attenuation.
  • Natural electromagnetic noise occurs partly from atmospheric discharges and partly from powerfull electric ionic currents in higher strata. Statistically, this noise increases with decreasing frequency. Particularly, this is the fact at the sea bed since the suppression of noise through sea water clearly increases with the frequency. However, the attenuation of the signals along the transmission line also will increase with the frequency. This is particularly the fact when the casing passes through rocks having low resistivity. For this reason, there will normally exist relatively much noise in the frequency range which conveniently is used for transmission of signals, namely 1-20Hz. For the same reason, it may be advantageous to employ the most advanced method for eliminating noise.
  • the invention is based upon the fact that an uninsulated well casing which is surrounded by more or less conductive rocks can be considered as a non ideal signal wire transmission line for transmitting signals. On this basis, equipment for transmitters and receivers has been developed for minimizing the energy consumption in connection with each transmitted signal.
  • the invention is further based on optimum impedance adaptation between the transmitter, the receiver and the casing based on the characteristic impedance of the casing at the point of connection. Further, it is achieved with the apparatus according to the invention, maximum suppression of geoelectromagnetic noise to the receiver by means of geometrical and adaptive cancelling of the noise area vector. Additionally, the apparatus is based on bi-phase modulation and correlation detection of the signal based on synchronous transmission and reception as well as phase-locking based on maximum correlation for the entire received signal.
  • Fig. 1 schematically discloses a sectional view through a producing well with a riser attached to an (not shown) over-lying platform
  • Fig. 2 discloses a corresponding view through a sub sea producing well
  • Fig. 3 discloses a temporarily abandoned well
  • Fig. 4 discloses a corresponding view through a permanently abandoned well
  • Fig. 5 discloses a sectional view through a permanently abandoned well with the transmitter and the receiver according to the invention
  • Fig. 6 discloses a sectional view in part of the transmitter of the apparatus
  • Fig. 7 discloses a block diagram for the transmitter
  • Fig. 8 discloses a sectional view in part of the receiver of the apparatus
  • Fig. 1 schematically discloses a sectional view through a producing well with a riser attached to an (not shown) over-lying platform
  • Fig. 2 discloses a corresponding view through a sub sea producing well
  • Fig. 3 discloses a temporarily abandoned well
  • Fig. 4 discloses a
  • Fig. 9 discloses a general view of the location of reference electrodes on the sea bed
  • Fig. 10 discloses a block diagram of the receiver
  • Figs. 11-14 disclose schematically various alternatives for connecting the transmitter to the casing
  • Fig. 15 discloses in sectional view and schmatically the structure of a connection means for insulating the casing
  • Fig. 16 discloses a modified structure of the connection means.
  • Fig. 1 discloses schematically a producing well with riser attachment to an overlaying platform (not shown).
  • the well is drilled but not completed with oil pipes.
  • a transmitter 1 is in the well connected to the casing 6 by means of connectors 10 and 11.
  • a receiver 2 is connected to a current detector 4, lying on the sea bed 3 and surrounding the well head.
  • information carrying signals, transmitted from the transmitter 1, are further transmitted to the surface, such as to a production platform, by means of conventional signal transmission, such as acoustic transmission or cable transmission.
  • Fig. 2 discloses a corresponding well completed without riser.
  • the transmitter 1 on one side is attached to the oil pipe and via the sealing of the oil pipe is connected to the casing 6.
  • Fig. 3 discloses a temporarily abandoned well.
  • the transmitter 1 is suspended in a seal 5 and connected to to the casing 6 with its connector 11 as well as through the seal 5.
  • the casing Above the seal 5 the casing is closed with a plug 31.
  • the transmitter 2 on the sea bed 3 will also measure the current from the casing 6 to the sea.
  • Fig. 4 depicts the apparatus according to the invention used in a permanently abandoned well.
  • the well head is here removed and the well is sealed along a major length.
  • the receiver 2 is connected directly to the casing 6, the latter having no direct electrical connection with the sea.
  • Fig. 5 shows schematically a permanently abandoned well with the apparatus according to the invention, integrated.
  • the transmitter 1 is shown more detailed in Fig. 6 and the receiver 2 is shown more detailed in Fig. 8.
  • the transmitter 1 can be suspended in a seal 5 and is connected to the casing 6 with the contacts 10 and 11, below and above a connector 12 respectively, the connector insulating an upper and lower part of the casing 6 electrically.
  • the casing is permanently cast to the sea bed by cement 32.
  • the cement forms an insulating layer between the casing 6 and the sea bed and contributes to reduce the transmission losses. In this connection it is essential that materials have been added to the cement, having low conductivity and thereby contributing to reduced the attenuation.
  • the receiver 2 is placed in the crater which is formed when the casing 6 is cut and pulled and electrically connected to the casing 6 by contacts 7.
  • Three sea bed electrodes 8 and a vertical electrode 9 also are connected to the transmitter 2.
  • the receiver 2 measures the signal current through the casing 6 to the sea bed electrodes and compensates adaptively the received signal with basis in the noise signal to the vertical electrode 9.
  • the received data from the transmitter 1 is decoded by correlation technique and stored in the receiver 2. The stored data then can be transmitted to the surface, e.g. acoustically to a vessel.
  • Data is transmitted from the dowhole transmitter to the receiver on the sea bed at even intervals.
  • the receiver is switched off in order to save power.
  • correlation technique is used. This assumes that the receiver will "know” exactly when the signals will arrive and then will recognize alternative signal forms, represented by "0" and "1".
  • two synchronously running clocks are used, one of which is located in the transmitter 1 and the other located in the receiver 2.
  • the clock in the receiver is adjusted to the transmitter clock after each message, considering the deviation between the two clocks.
  • the correlation algorithm is calculated from the total message being transmitted.
  • Fig. 6 discloses schematically the transmitter 1 and its structure.
  • the transmitter comprises a sensor part 14 for measuring desired parameters such as temperature and pressure, one electronic unit 13 for the transmitting function, batteries 15 as well as contacts 10 and 11 for establishing contact between the transmitter 1 and the casing 6.
  • the transmitter 1 has a neck 18 for connection of a cable during the installation of the transmitter in the well where also the cables make it possible to carry out electrical control of the transmitter after installation. The cable is released from the transmitter before the well is sealed by means of a seal 5 and thereafter plugged.
  • the contacts 10 and 11 are electrically insulated from the transmitter which is covered with an external insulating layer.
  • the contacts 10 and 11 are forcibly pressed radially outwards after the transmitter 1 has been positioned correctly and will cut into the casing 6 above and below the connector, respectively which insulates the upper and lower parts of the casing from each other.
  • the connector 12 is formed as an extended sleeve for the casing 6 and is lowered together with the casing.
  • the transmitter 1 is shown schematically in the block diagram of Fig. 7.
  • Signals from the transmitter are low frequency sinusoidal currents, 1-20Hz where the data message is modulated 180° phase shift (biphase modulation).
  • the drive signal for the power amplifier and the impedance transformer is digitally synthesised by means of a micro processor.
  • the signal is based on an oscillator or a clock of high stability.
  • the data messages from the sensors are transmitted via a multiplexor and in an analogue manner to the digital converter. Digital signals are transmitted directly to the synthesizer.
  • the batteries will feed the transmitter unit via power regulator which converts the prevailing battery voltage to a correct supply voltage with minimum power loss.
  • the transmitter 1 can be connected to the casing 6 in two places, arranged widely apart such as shown in Fig. 11.
  • the impedance between these places will be determined by the distance between the places as well as the electrical characteristics of the pipe and it's surroundings. For practical, useful distances relatively large losses will occur with this solution.
  • FIG. 12 Another alternative is shown in Fig. 12 where the casing 6 has been cut between the transmitter attachment points to the casing in order to insulate an upper and lower part of the casing electrically from each other. Adequately insulated, the impedance in the attachment point will appear directly from the characteristic impedance of the casing. A practical drawback with this solution is that the casing will be lost and thus it's mechanical functions.
  • the upper and lower part of the casing 6 can also be insulated by means of a connector 12.
  • the connector 12 is shown schematically in Fig. 15 and is internally and externally covered with an electrically insulating material 24. This material has good cementing properties and sufficient mechanical strength to withstand the well pressure and any other tension on the casing.
  • the connector 12 is attached to the casing 6 by means of an ordinary sleeve 25 while an internal steel pipe 26 is used to obtain a strong mechanical connection between the upper and lower part of the casing.
  • the insulating material 24 is used to prevent a "short circuit" across the insulation gap if the formation and/or the well fluid should be strongly conductive at this point.
  • the connector 12 can be made of a highly resistive material.
  • Fig. 14 shows another embodiment of the invention where the connector 12 is released from the casing 6.
  • the transmitter output is transferred to a toroidally wound induction coil 27 which is arranged outside the casing 6 and which axially induces a voltage in the pipe.
  • the induction coil 27 in Fig. 16 is fed by the transmitter via the connection points 29, the magnetic field is established by a laminated iron core 28 surrounding the casing 6.
  • the induction coil 27 and the iron core 28 are surrounded by a case 30 having a diameter like a sleeve with a tick wall.
  • the advantages of the above described connector are that signal voltages are established directly in the casing 6 without having to insulate the upper and lower parts from each other. At the same time it works independently as an impedance transformer and permits transmission from the transmitter at a higher voltage level and with reduced loss.
  • the receiver 2 is shown in detail schematically in Fig. 8 and consists of the electronic unit 20 of the receiver which cancels noise and demodulates the signals, the battery unit 15 for the supply of energy to the receiver and for transmitting the information by means of the acoustic transmitter 22 and its aerial 23.
  • the receiver is connected to the casing 6 by means of the contacts 7 which forcibly are pressed into the casing and thus create an interface between the receiver and the casing with little resistance.
  • the signal from the casing 6 is measured in relation to a system with reference to the proportions of the electrodes 8 arranged on the sea bed and a vertical electrode 9.
  • the horizontal reference electrodes 8 are lying on the sea bed in precise orientations as shown in Fig. 19, with an angular distance of 120°.
  • the vertical electrode 9 is formed like a floating rope with a built in electrode and extends straight up from the receiver 2 some meters above the sea bed 3.
  • the reference electrodes are built for reducing noise in the signal frequency band.
  • signals arrive from the casing 6 and the sea bed electrodes 8.
  • the three reference signals are added.
  • the vector sum thereby achieved, is ideally zero and is used as a reference point for the signal from the casing 6.
  • a signal also arrives from the vertical electrode 9. This is used in an adaptive filter in order to suppress the vertical component in the geoelectromagnetic noise induced in the casing.
  • the signal from the casing is amplified and filtered for the noise components lying near the signal frequency. Then the signal is compared with the signal from the vertical electrode 9 and the filter II as shown in Fig. 10 and is automatically adjusted in order to minimize the difference.
  • the suppressed transmitter signal is added to the noise which naturally is induced in the casing 6 and which the receiver 2 is adjusted to cancel. This results in the fact that the filtered signal to the correlator will be relatively pure.
  • the filtered input signal is correlated with a built in time reference signal.
  • This is built up from an ultra stable oscillator and a synthesizer of the same type as provided for the transmitter 1.
  • the reference signal is indicating to the correlator exactly when the signal from the oil well is expected to be received.
  • the filter III By means of the filter III the curve is adjusted in the same way as the signal is altered through the transmission via the casing 6.
  • the correlator will both indicate how the signal pattern will look like and by how much the time reference should be adjusted in order to obtain maximum correlation.
  • the time reference is adjusted and likewise the reference signal is adjusted so that the form of the curve will be correct for all changes of the signal.
  • the adjusted reference signal is used to verify if the first hypothesis of the signal pattern is correct, after which the oscillator is adjusted in such a way that the time reference will be the best possible for the next sequence to be received.

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  • Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Remote Sensing (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geophysics (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Electromagnetism (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Arrangements For Transmission Of Measured Signals (AREA)
  • Synchronisation In Digital Transmission Systems (AREA)
  • Lubricants (AREA)
  • Removal Of Floating Material (AREA)
  • Forms Removed On Construction Sites Or Auxiliary Members Thereof (AREA)

Claims (7)

1. Procédé de transmission de données à la surface d'un puits de pétrole sous-marin, dans lequel des signaux électromagnétiques sont transmis par une unité d'émission (1) placée dans le puits de pétrole, les signaux comprenant des données de paramètres enregistrés, dans lequel le cuvelage (6) du puits de pétrole est utilisé comme ligne de transmission jusqu'à une unité de réception placée à l'extrémité supérieure du puits de pétrole, et dans lequel les signaux reçus par l'unité de réception (2) sont transmis par l'unité de réception à une autre unité de réception placée à la surface, caractérisé par
l'émission des signaux cycliquement dans le temps, du puits au fond de la mer (3) et du fond de la mer à la surface,
l'activation par horloge de ladite émission, l'activation par horloge de l'unité de réception (2),
la synchronisation de l'horloge de l'unité de réception avec l'horloge de l'unité d'émission, et
le filtrage des signaux reçus à l'unité de réception, pour éliminer le bruit électromagnétique.
2. Procédé suivant la revendication 1, caractérisé par la transmission acoustique des signaux filtrés, de l'unité de réception (2) à l'unité de réception placée à la surface.
3. Procédé suivant la revendication 1, caractérisé par la transmission des signaux filtrés de l'unité de réception (2) à l'unité de réception placée à la surface, au moyen d'un câble.
4. Procédé suivant l'une des revendications 1 à 3, caractérisé en ce que le bruit électromagnétique est capté dans une électrode verticale (9) placée au centre d'un groupe d'électrodes de référence horizontales (8) disposées radialement et placées au fond de la mer, et en ce que lesdits signaux captés sont filtrés dans l'unité de réception (2).
5. Appareil pour la transmission de données à la surface d'un puits de pétrole sous-marin, lesdites données concernant des paramètres enregistrés, qui comprend:
une unité d'émission (1) placée dans un cuvelage de descente (6) prévu dans le puits de pétrole, ladite unité d'émission comportant des moyens de détection (14) pour mesurer lesdits paramètres, une unité électronique d'émission (13) et un accumulateur d'émetteur (15),
une unité de réception (2) placée à l'extrémité supérieure du puits de pétrole, ladite unité de réception comprenant une unité électronique de réception (20), des moyens de filtrage (I, II, III) pour filtrer les signaux reçus par l'unité de réception, et un accumulateur de récepteur (15), caractérisé par
une ligne de transmission s'étendant entre l'unité d'émission (1) et l'unité de réception (2) pour la transmission de signaux de données relatifs auxdits paramètres, ladite ligne de transmission étant une partie dudit cuvelage (6),
des moyens de connexion (10, 11; 29) pour connecter l'unité d'émission (1) au cuvelage (6),
une horloge d'émetteur prévue dans l'unité d'émission (1),
une horloge de récepteur prévue dans l'unité de réception (2),
des moyens pour activer par horloge l'unité d'émission (1), et
des moyens de synchronisation (CORRELATEUR, FIG. 10) pour synchroniser l'horloge de récepteur avec l'horloge d'émetteur.
6. Appareil suivant la revendication 5, caractérisé en ce qu'il comprend un connecteur (24) pour diviser le cuvelage (6) en une partie supérieure et une partie inférieure, ledit connecteur comportant une isolation (24) entre les parties supérieure et inférieure du cuvelage, lesdits moyens de connexion d'émetteur reliant l'unité d'émission (1) à la partie supérieure du cuvelage.
7. Appareil suivant la revendication 5, caractérisé en ce que les moyens de connexion d'émetteur sont raccordés à un enroulement d'induction (27) comprenant un noyau inférieur en fer doux (28), ledit enroulement étant bobiné autour d'une partie du cuvelage (6).
EP88850358A 1987-10-23 1988-10-21 Dispositif et procédé pour transmettre des données à la surface à partir d'un puits de pétrole Expired - Lifetime EP0314654B1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
NO874428A NO163578C (no) 1987-10-23 1987-10-23 Fremgangsmaate og innretning for overfoering av maaledata fra en oljebroenn til overflaten.
NO874428 1987-10-23

Publications (2)

Publication Number Publication Date
EP0314654A1 EP0314654A1 (fr) 1989-05-03
EP0314654B1 true EP0314654B1 (fr) 1992-01-08

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Family Applications (1)

Application Number Title Priority Date Filing Date
EP88850358A Expired - Lifetime EP0314654B1 (fr) 1987-10-23 1988-10-21 Dispositif et procédé pour transmettre des données à la surface à partir d'un puits de pétrole

Country Status (3)

Country Link
EP (1) EP0314654B1 (fr)
ES (1) ES2029077T3 (fr)
NO (1) NO163578C (fr)

Cited By (2)

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Publication number Priority date Publication date Assignee Title
US6772082B2 (en) 2001-04-26 2004-08-03 Abb As Method for detecting and correcting sensor failure in oil and gas production system
WO2018236352A1 (fr) * 2017-06-20 2018-12-27 Halliburton Energy Services, Inc. Procédés et systèmes à synchronisation de fond de trou sur la base d'un synthétiseur numérique direct (dds)

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FR2681461B1 (fr) * 1991-09-12 1993-11-19 Geoservices Procede et agencement pour la transmission d'informations, de parametres et de donnees a un organe electro-magnetique de reception ou de commande associe a une canalisation souterraine de grande longueur.
GB9620074D0 (en) * 1996-09-26 1996-11-13 British Gas Plc Pipeline communication system
US6018501A (en) * 1997-12-10 2000-01-25 Halliburton Energy Services, Inc. Subsea repeater and method for use of the same
US6018301A (en) * 1997-12-29 2000-01-25 Halliburton Energy Services, Inc. Disposable electromagnetic signal repeater
NO985712L (no) * 1998-01-27 1999-07-28 Halliburton Energy Serv Inc Nedihulls telemetrisystem og fremgangsmåte for fjernkommunikasjon
US6439046B1 (en) * 2000-08-15 2002-08-27 Baker Hughes Incorporated Apparatus and method for synchronized formation measurement
FR2854425B1 (fr) * 2003-04-30 2005-07-29 Gaz De France Procede et dispositif de transmission d'informations entre une cavite saline et la surface du sol
GB0426594D0 (en) * 2004-12-03 2005-01-05 Expro North Sea Ltd Downhole communication
US8077053B2 (en) * 2006-03-31 2011-12-13 Chevron U.S.A. Inc. Method and apparatus for sensing a borehole characteristic
US8390471B2 (en) 2006-09-08 2013-03-05 Chevron U.S.A., Inc. Telemetry apparatus and method for monitoring a borehole
US7863907B2 (en) 2007-02-06 2011-01-04 Chevron U.S.A. Inc. Temperature and pressure transducer
US7810993B2 (en) 2007-02-06 2010-10-12 Chevron U.S.A. Inc. Temperature sensor having a rotational response to the environment
US8106791B2 (en) 2007-04-13 2012-01-31 Chevron U.S.A. Inc. System and method for receiving and decoding electromagnetic transmissions within a well
US7841234B2 (en) 2007-07-30 2010-11-30 Chevron U.S.A. Inc. System and method for sensing pressure using an inductive element
US7636052B2 (en) 2007-12-21 2009-12-22 Chevron U.S.A. Inc. Apparatus and method for monitoring acoustic energy in a borehole
US9547104B2 (en) 2007-09-04 2017-01-17 Chevron U.S.A. Inc. Downhole sensor interrogation employing coaxial cable
NO20074796L (no) * 2007-09-20 2009-03-23 Ziebel As Framgangsmate ved forlating av en petroleumsbronn
US8353677B2 (en) 2009-10-05 2013-01-15 Chevron U.S.A. Inc. System and method for sensing a liquid level
US10488286B2 (en) 2009-11-30 2019-11-26 Chevron U.S.A. Inc. System and method for measurement incorporating a crystal oscillator
US8575936B2 (en) 2009-11-30 2013-11-05 Chevron U.S.A. Inc. Packer fluid and system and method for remote sensing
US10100634B2 (en) * 2015-09-18 2018-10-16 Baker Hughes, A Ge Company, Llc Devices and methods to communicate information from below a surface cement plug in a plugged or abandoned well
WO2017099807A1 (fr) * 2015-12-11 2017-06-15 Halliburton Energy Services, Inc. Procédés et systèmes de surveillance de champ électrique de subsurface faisant appel à un agencement de ciment à focalisation de courant
GB2552557B (en) 2016-10-25 2018-08-29 Expro North Sea Ltd Communication systems and methods
WO2018178606A1 (fr) * 2017-03-31 2018-10-04 Metrol Technology Ltd Installations de surveillance de puits
US11156062B2 (en) * 2017-03-31 2021-10-26 Metrol Technology Ltd. Monitoring well installations
US11448062B2 (en) 2018-03-28 2022-09-20 Metrol Technology Ltd. Well installations
BR112020019422B1 (pt) * 2018-03-29 2024-01-09 Metrol Technology Ltd Sistema de comunicação de fundo de poço, método de comunicação de fundo de poço e instalação de poço submarino de petróleo e/ou gás

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NO844838L (no) * 1984-12-04 1986-06-05 Saga Petroleum Fremgangsmaate ved registrering av forbindelse mellom oljebroenners reservoarer.

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6772082B2 (en) 2001-04-26 2004-08-03 Abb As Method for detecting and correcting sensor failure in oil and gas production system
WO2018236352A1 (fr) * 2017-06-20 2018-12-27 Halliburton Energy Services, Inc. Procédés et systèmes à synchronisation de fond de trou sur la base d'un synthétiseur numérique direct (dds)
US10975688B2 (en) 2017-06-20 2021-04-13 Halliburton Energy Services, Inc. Methods and systems with downhole synchronization based on a direct digital synthesizer (DDS)

Also Published As

Publication number Publication date
NO163578B (no) 1990-03-12
NO163578C (no) 1990-06-20
EP0314654A1 (fr) 1989-05-03
NO874428L (no) 1989-04-24
NO874428D0 (no) 1987-10-23
ES2029077T3 (es) 1992-07-16

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