FR2768175A1 - CABLE, IN PARTICULAR FOR WELLBORE, AND INSTALLATION, AND METHOD FOR THE ACQUISITION AND PROCESSING OF DATA, USING SUCH A CABLE - Google Patents

Abstract

The present invention in some of its aspects describes a wellbore cable (L), comprising one or more optical fibers (O) themselves comprising one or more Bragg gratings. Such a cable is used in a system (S) according to the present invention comprising a suitable source (B) with a broad spectrum, a detector system (D) and other stations (by way of nonlimiting example of the isolators (I), couplers (C), computers and acoustic transmitters (A)) to measure: the length of a cable in the well (L), the temperature at a location in the well, and the tension or stretch of the cable , and other conditions prevailing in the well. The invention also relates to methods of implementing such a cable for such purposes. A cable of the invention comprises a hollow metal tube which houses without tension, at least one optical fiber; according to one aspect of the invention, the optical fiber or fibers which may be two, three, four or more, each comprise at least one, if not two, three, four, five or more Bragg gratings; and according to another aspect, such a cable or line comprises one, two, three, four or more, optical fibers arranged outside of said metal tube.

Description

 The present invention relates to the field of armored cables used in the electrical logging of oil or gas wells and to the control of the length of such cables, their temperature and the voltages which are imposed on them. More particularly the present invention relates to a control system comprising at least one optical fiber provided with at least one Bragg grating.

 Logging cables with electric conductors transport measuring instruments in geological boreholes in order to generate signals reflecting the properties of the geological formations crossed at various depths of the well. This is generally done at the same time that the instrument is removed from the well by winding the logging cable on a winch or similar winding device, at the same time as the signals are generated by the instruments and a recording of the measurements is performed.

 In certain systems of the prior art, the measurement of the depth of an instrument in the well is carried out by means of a calibrated wheel in positive contact with the cable. The calibrated wheel always corresponds to the travel of the cable during its descent or its ascent into the well by the winch. In some cases, a plurality of magnetic markers are arranged equally spaced along the cable. The wheel can be coupled to a mechanical counter to indicate the length of cable unwound on the wheel, or the wheel can be coupled to an encoder connected to a counter or to a computer to electronically indicate the length of cable unwound on the wheel. Such wheels can accurately determine the total length of cable that has been unwound by the wheel into the well, but the actual depth of the instrument in the well may not correspond exactly to the total length unwound on the wheel, this is because the cable is subject to tension, or elongation, when it moves.

 Both temperature and weight affect cable tension. The total weight of a cable lowered into a well can be of the order of 500 pounds (250 kg) per 1000 feet (300 m) of cable, and the instrument itself has significant weight when it is in the well, which weight can vary depending on whether more or less the interior space of the instrument is occupied by air, and the density of the fluid present in the well. The measurements may thus have been made at depths different from ten meters or more, from those indicated by the calibrated wheel because of the stretching of the cable induced by the tension when the instrument is withdrawn from the well.

 The most random parameter that affects cable tension is friction, which can increase the stretching of the cable when it is removed or lowered into the well, since the roughness of the surface of the well is unknown nor the coefficient of friction of the geological formations crossed by the well. The drilling mud or fluids present in the well can vary in viscosity depending on the depth of a given well, making the determination of friction effects often difficult.

US Pat. No. 4,803,479 (GRAEBNER et al.) Describes a method of measuring depth aimed at compensating for the value of the stretching of the cable, which method comprises measuring the phase shift of an electrical signal sent through the entire cable and returned to the surface equipment, the measurement being given by the phase shift with respect to the same signal sent through a reference cable placed on the ground surface and of invariable length. In the method of the GRAEBNER patent, the phase shift of an electrical signal of constant frequency depends only on the variation of the transmission time of the signal1 so that the phase shift corresponds to the variation of length of the electrical conductors of the cable. A limitation of the GRAEBNER method lies in the fact that the variation in length of the electrical conductors of the cable may not correspond exactly to the variation in the length of the cable;
An electrical logging cable conventionally comprises a plurality of insulated electrical conductors covered with steel reinforcing wires wound in a spiral. Such a digraphy cable typically comprises seven conductors, six of which are wound in a spiral around the seventh.

When such a multi-conductor cable is stretched, part of the stretch is absorbed by the unwinding of the spirally wound conductors, so that the length of the cable increases more than the actual length of the conductors increases. Another limitation of the method described in the '479 patent (GRAEBNER) lies in the fact that the ratio, called "scale factor", of the variation in the length of the cable with respect to the phase shift of the electrical signal, must be determined for each particular case because the properties of transmission of the electrical signal may vary somewhat from cable to cable. Yet another limitation of the method described in the '479 patent (GRAEBNER) is the need to use additional conductive elements on the ground surface to provide a fixed length phase reference to compare with the phase variation. in the logging cable. A substantial length of cable to be used as a fixed reference length may occupy significant storage space, which may not be practical.

 Often small lengths of cable, such as 100 to 300 feet (30 to 100 meters), are cut from the end of a particular cable lowered into a well, when that end of the cable is worn or damaged. In other circumstances, the cable is cut to recover a damaged instrument in the well, the cable being subsequently reassembled by splicing.

When a cable is cut, the scale factor must be determined again by assigning the cable a known amount of stretch and measuring the phase shift caused by the known stretch. It is difficult to recalibrate the scale factor at a location in the well since the equipment designed to impart a known stretch to the cable can typically only be located with specialized equipment.

 The system of US Pat. No. 4,9803,479 also has a deficiency in that the precision of the measurement of the phase shift declines rapidly with an increase in the frequency of variation of the length of the cable. Higher frequency variations in the cable stretch value can be caused by jerky movement of the logging instrument when the combination of gravity and friction from the well momentarily exceeds the upward pull of the logging cable up 'that it is violently released in a movement analogous to that of a spring, when the frictional force is exceeded when the tension of the cable up has grown sufficiently.

 US Patent 3,490,149 (BOWERS) describes a method for determining the depth of logging instruments in a well.

The system includes an accelerometer for measuring the acceleration of the coaxial well logging instrument. Acceleration measurements from the coaxial logging instrument to the well are doubly integrated to provide a determination of the variation in the axial position of the logging instrument. The variation of the axial position determined from the doubly integrated measurements of the accelerometer is used to adjust the measured position of the instrument as determined by the measurements of the length of cable which has passed through a measuring device. sure of the length of cable down into the well. A disadvantage of the system is that the doubly integrated acceleration measurements must be limited in band by a filter intended to extract the output of direct current and alternating current at very low frequency, from the accelerometer and to correct the "drift of zero "(also known in the art as" systematic error "). If the acceleration of the instrument drops below a cutoff frequency of the filter, then low frequency acceleration of the instrument can be caused by forces such as friction which modify the tensile force of the cable, and therefore its length, may not be detected. As a result, the system is used only to correct depth measurements for higher frequency accelerations of the logging instruments.

 The patent US4,545,242 (CHAN) describes an improvement of the method described in the patent 1149 (BOWERS). The system includes loop amplifiers to decrease an error signal generated in the process of integrating accelerometer measurements to determine the true position of the logging instruments in the well. This system is limited in that it has no response means below the lowest breaking frequency of a filter applied to the output of the accelerometers. the systems described in '149 (BOWERS) and' 242 (CHAN) are unable to provide precise depth information if the cable is "stretched" at frequencies below the breaking frequency of the filter applied to the accelerometer .

 The methods which include the reading of magnetic markers have several disadvantages: - 1) the sharpness of the magnetic markers decreases with use and time and consequently the precision of the position of the markers also decreases; - 2) the markers need periodically to be re-magnetized; - 3) the line length between the magnetic markers, supposed to be fixed, is only fixed approximately since the line stretches with use, which consequently increases the distance between the markers; and - 4) a slip is induced by the friction of the measuring wheels, particularly when the cables are wet and / or covered with drilling mud when they exit the well.

 Various known armored electrical cables have one or more electrical conductors used to supply electrical power to logging instruments and to transmit signals from these instruments to surface equipment for processing. These cables have reinforcements of steel wires wound in a spiral around the electrical conductors to provide resistance to torsion, traction and abrasion.

 A wide variety of cables in the prior art have optical fibers and implement optical telemetry at high frequency and at higher data transmission speeds than those obtained by electrical transmission.

 Cables known from the prior art have optical fibers contained in a steel tube; another combination of the prior art optical fiber and the logging cable comprises an optical fiber in a plastic sheath instead of one or more electrical conductors; Another combination of the prior art optical fiber and electric cable comprises an optical fiber incorporated in a metal tube surrounded by twisted copper twists to conduct electrical power and electrical signals.

 Patent US-5,495,547 by the same Applicants describes a logging cable with a combination of optical fiber and electrical conductor. This patent deals with the problems associated with the aforementioned cables of the prior art and is incorporated in full in the present description for all practical purposes. The patent US Pat. No. 5,495,547 describes, as illustrated in FIG. 1A, in some of its embodiments, a logging cable comprising first elements made of a steel wire coated with copper surrounded by copper twists and covered of an electrically insulating material, and at least one second element comprising at least one optical fiber incorporated in a metal tube surrounded by copper twists and covered by the electrically insulating material. The first elements and at least the second element are arranged in a central bundle. The second element is positioned in the bundle so as to be wound in a spiral around the axis of the central bundle. The bundle is surrounded by reinforcing wires wound in a spiral outside the bundle. A cross section of such a prior art logging cable 10 is illustrated in FIG. 1A and is described in US Pat. No. 5,495,547. Parts of the cable 10 are shown in Fig.lB and 1C. The cable 10 comprises seven conductive elements insulated by plastic material and positioned in a central bundle 15 having a substantially regular hexagonal configuration, six of these elements surrounding the seventh. The first elements 16 are, according to one aspect of the invention, insulated electrical conductive elements comprising a copper-coated steel wire with a diameter of about 0.027 inch (0.68 mm) surrounded by nine copper wires having each a diameter of about 0.0128 inch (0.32 mm). The first elements 16 comprise an external insulating jacket made of plastic material resistant to humidity and heat, such as polypropylene or the ethylene-tetrafluoroethylene copolymer ("ETFE") sold under the brand name of "TEFZEL" from E.l. Du Pont de Nemours & Co. Each of the second elements 18 comprises, inter alia, an optical fiber disposed inside a stainless steel tube. The cable 10 comprises two of the second elements 18 positioned symmetrically in any of the six external locations of the regular hexagonal configuration formed by the seven elements.

 Empty spaces inside the hexagonal structure of the seven elements 15 (16,18) are, according to one aspect of the invention, filled with a filling material 17, for example plastic material such as neoprene or ETFE. The filling 17 maintains the relative position of the seven elements 15 (16,18) inside the cable 10. The elements 15 (16,18) and the filling 17 are covered with galvanized steel reinforcing wires wound in spirals forming an internal armed sheath. The internal reinforcement sheath 14 is itself externally covered with galvanized steel reinforcement wires wound in spirals forming an external reinforcement sheath 12. The internal reinforcement sheath 14 and the external reinforcement sheath 12 are intended to provide the cable with significant tensile and abrasion resistance. According to one aspect of the invention the cable 10 is intended to be used in a chemically hostile environment such as a well having significant quantities of hydrogen sulfide, and the reinforcing wires 12, 14 may also be composed of a cobalt-nickel alloy such as that identified by the industrial code MP-35N.

 One 18 of the second elements shown in more detail in FIG. 1 B comprises an optical fiber 22 contained in a metal tube 24 made of stainless steel to provide corrosion resistance. The tube 24 has, according to one aspect of the invention, an outside diameter of 0.033 inch (0.83 mm) and an inside diameter of 0.023 inch (0.58 mm). The tube 24 provides the optical fiber 22 with protection against abrasion and deformation and prevents fluids from the well from entering the cable. The tube 24 can be plated with copper in order to reduce its electrical resistance, and be surrounded by twelve twists of copper wire generally represented by 26. The twists of wire 26 can each have a diameter of 0.01 inch (0.25 mm ). The combination of the tube 24 and the twists 26 constitutes a conductor having an electrical resistance of less than 10 ohms per length of 1000 feet. The tube 24 and the copper twists 26 are further covered with heat-resistant insulating plastic 20, such as ETFE, or polypropylene. The outside diameter of the insulator 20 of the second member 18 is substantially the same as the outside diameter of the insulator of the first member 16, so that the hexagonal configuration of the seven members, as shown in the cross section of FIG . 1A is substantially symmetrical, despite the relative position of the second element 18 inside the hexagonal structure of the beam 15.

Second elements 18 can be positioned in any of the six external positions of the hexagonal structure as shown in FIG. 1k The cond element 18, according to one aspect of the invention may be located at an external location of the hexagonal structure of the bundle 15, owing to the fact that the elements 16, 18 of the external locations are wound in a spiral in a central position around the 'element. For reasons such as the lateral decrease in the diameter of the nominal diameter under axial tension, the unwinding of the helical layer and the greater overall length of the external elements wound in a spiral relative to the length of the central element 18, the elements 16 , 18 positioned outside are subjected to a reduced axial tension compared to the axial elongation of the cable, which also reduces the probability of axial failure induced by the tension of the tube 24 and of the fiber 22.

The second elements 18, according to one aspect of the invention, are positioned in two external locations opposite one another in the hexagonal structure.

 Fig.lC shows in more detail a cross section of the first element 16. The first element 16 has, according to one aspect of the invention, a steel wire 28 copper clad to have an outside diameter of about 0.027 inch (0 , 68 mm), which reduces the electrical resistance of the wire 28. The copper-coated wire 28 is further surrounded by nine copper twists, represented overall by 30 and having an outside diameter of 0.0128 inch (0.32 mm ). The combination of steel wire 28 and copper twists 30 has an electrical resistance of less than seven ohms per length of 1000 feet. The twists 30 are covered with an electrically insulating material 32 such as polypropylene or PTFE. The second elements 18 are designed so that the combination of the tube 24 and the twists of wire 26 has an outside diameter allowing the insulating material to give the second element 18 substantially the same electrical performance per unit of length as that of the first element 16 The cable assembly will have substantially the same signal transmission and electrical power properties as the cables of the prior art.

 Patent US-5,541,587 co-filed, and incorporated into the present Application for all practical purposes, discloses a system for determining the depth of a logging instrument lowered into a well in a geological formation. A particular embodiment of the system comprises a circuit for generating a measurement of the phase shift of a sinusoidal electrical signal transmitted through the cable, the phase shift of the signal corresponding to the length of the cable. The system also includes an accelerometer located inside the instrument and electrically connected to a bandpass filter. The double integrator calculates the position of the coaxial instrument at the well. The phase shift measurement is sent to a low-pass filter. The low pass filter and the band pass filter have at least some degree of bandwidth overlap. The output of the integrator is used to generate a scale factor which is applied to the measurement of the filtered phase shift. The measurement of the affected phase shift of the scale factor is transmitted to a background computer as a trigger for a signal generated by a background encoder and as integrated measurements of the accelerometer. The background encoder signal corresponds to the amount of cable present in the well. The downhole computer calculates the depth of the instrument in the well by summing the phase shift measurements affected by the scale factor, the integrated accelerometer measurements and the encoder measurements.

 Fig.2A and 2B show a cable of the prior art described in US-5,541,587. The cable is a typical multi-conductor well logging cable, the periphery of which is composed of reinforcing wires 30 wound in spirals, of steel for example. Electrical conductors inside the reinforcing wires include a central conductor 32 and external conductors 31 wound in a spiral. The central conductor is substantially collinear with the length of the cable and is substantially coaxial with the cable over its entire length.

 There has long been a need for a logging cable monitoring system that accurately indicates cable length, cable tension, and / or temperature at a cable location.

 The subject of the present invention is therefore a logging cable device, an installation comprising such a cable, and a method of obtaining data for measuring the aforementioned quantities, using the cable and / or the installation comprising it, these objects of the invention comprising, taken separately or in combination, the provisions listed below.

Thus, and more precisely, a cable device in particular intended in particular for well logging operations, is characterized in its generality in that, having spaced ends comprising a first and a second end, the well logging operations comprising measuring the tension, or the elongation, of the cable,
said cable comprises at least one optical fiber which extends from its pre
first end to its second end, and in that said fiber opti
that at least incorporates at least one Bragg grating;
preferably:
- said optical fiber at least is one of the fibers of a plurality of optic fibers
what,
- said Bragg network at least is one of the networks of a plurality of networks
from Bragg,
- the cable incorporates a plurality of reinforcing wires around said optical fiber
at least,
- Said plurality of optical fibers comprises at least two optical fibers es
paced from each other, each incorporating a plurality of networks of
Bragg,
- the cable includes a hollow metal tube extending from the first ex
end of the cable to its second end,
- the said at least two optical fibers spaced from each other, including
at least a first optical fiber and at least a second optical fiber
that, the first optical fiber being freely contained, or relaxed, in the
said hollow metal tube,
- the second optical fiber is placed in the said cable device of my
as it stretches when the cable itself stretches;
- the hollow metal tube is made of stainless steel,
- the cable comprises a plurality of copper twists wound around the
hollow metal tube, the so-called twists extending from the first to the
end of said cable,
- an insulating material is placed between the first and second optical fibers,
- The cable comprises at least one conductive wire extending from its first to its
second end.

An installation in accordance with the present invention and incorporating at least one cable as described above, is characterized in its generality in that it comprises:
- a control system, meaning by system a set of electrical means
truncations, optics and optoelectronics to process data and effec
kill the measures,
- a wire line provided with a top end and a bottom end,
said line being connected to said system and comprising the wiring device
fiber optic wheat to Bragg gratings,
- an optical coupler connected to the device, or system, of control and to the said
fiber optic at least,
- a light source connected to the control device to send an if
general light in said optical fiber at least,
- a detector connected to the control device to detect a reflected signal
from at least one Bragg network,
- an isolator to prevent reflected light from entering the source,
- a mobile acoustic transmitter connected to the control device and arranged
near the wire line, and intended to transmit an acoustic signal to
a scrolling Bragg grating.

A method of obtaining data, in accordance with the
present invention, implementing a cable and / or an installation such as
described above, is generally characterized in that it comprises the steps
consisting of:
- introduce the cable into a well which sinks into the ground from the surface of the
ground,
- to send a signal, thanks to transmission means, to at least one pre
mier Bragg network,
to receive the signal by means of reception, and
- to process the signal to obtain data,
Preferably, said method further comprises the steps consisting in:
data including data relating to the cable length com
taken between the ground surface and at least one of two Bragg gratings, the
said networks being spaced from each other by a distance from a transmitter
acoustic being positioned in the vicinity of the cable so that an acoustic signal
that can be transmitted to, and perceived by, a Bragg grating crossing the
acoustic transmitter, each network having an identifi
cation,
- send an acoustic signal to the first Bragg grating at a location
known with respect to the acoustic transmitter and to capture the wave from the network of
Bragg which derives from it and which identifies this first network, and
- calculate the distance from the acoustic transmitter to the second d
Bragg bucket based on knowledge of distance d and employment
cementing of the first network;
More preferably, the said method further comprises the steps consisting in:
the said first Bragg grating at least being one of the grids of a plurality
of spaced apart networks, and a terminal Bragg network being
located at the lowest end of the fiber in the cable device,
- to send a signal from a broadband source through at least one
fiber optic to the terminal Bragg network,
- to be picked up with a sensor placed at a known distance from the Bragg grating,
a return signal from the terminal network to the sensor as well as the
signal return path from the terminal network to said course
and
- calculate the length of the wire line, therefore of the cable device, from the
sensor to the terminal network;
More preferably, the said method further comprises the steps consisting in:
said Bragg grating at least having a wavelength identifying it,
- to send an interrogation signal from a bottom transmitter, to said pre
at least Bragg network,
- to receive, thanks to a reception device, the signal reflected from said re
Bragg bucket at least, and
- to calculate the line voltage located on said network at least in determi
the difference with the network wavelength by calculating the difference
between the wavelength of the reflected signal and the network wavelength.

Finally, and more preferably, the said method further comprises the steps consisting in:
each said Bragg grating at least having a single wavelength
(nominal),
- introduce the cable and the network to a deep location in the well,
- measure the network wavelength at this deep location,
- calculate the deviation of; wavelength between the single wavelength of the RV
bucket and the wavelength measured at the known deep location, and
- to determine the temperature at the said deep location of the well, using
the calculated difference.

 Thus, the present invention, in certain embodiments provides a system for precise determination of the length of a cable or a line in a wellbore in order to locate an instrument on the cable in the well, and therefore the place where the instrument is active to make a measurement.

According to one aspect, the installation comprises a cable, a multi-wavelength emitting light source interconnected on the surface with the cable, the cable comprising one or more optical fibers as said below, provided with one or more networks. of Bragg, and a coupler coupling the optical fiber and the source
The use of Bragg gratings provides several advantages. The network is a permanent part of the line, for example it is not as easily erasable as magnetic markers are and it does not need to be "refreshed" as a magnetic marker should be. The distance between two networks can be easily determined in real time with appropriate instrumentation.

In an embodiment in which such a system is used for a separate measurement of temperature off, two optical fibers are used each with a plurality of equally spaced networks. One of the optical fibers is placed freely inside a metal tube (for example steel or stainless steel, for example in place of one of the outer conductors of the cable (by way of nonlimiting example, a cable such than that of Fig. 1A or
Fig. 2A). The other fiber is placed in place of a central conductor of the cable (by way of nonlimiting example, a cable such as that of FIG. 1A or of FIG. 2A). In another aspect, the tube is made of stainless steel with copper twists and is used as a conductor. One or more conductors can be used.

 Methods according to the present invention using systems as described herein include methods for determining the temperature prevailing in a well, methods for measuring the tension of a cable in a well, and methods for determining the length of a cable in a well.

 The systems and methods according to the present invention can be used in a large number of situations. When the logging instrument and / or other downhole devices are conveyed via the drill pipe (conveyed tube logging) or by means of mechanical downhole propulsion devices such as tractors or crawler, the suitability of the present invention for determining a localized line stretch, aid in determining and locating jams and / or "nests"; determining the effective tensile force at high angles and / or in the horizontal sections when pulling out of the horizontal section or out of the well; and determining the line feed speed when pulling in and / or out of the horizontal sections to prevent jamming and / or "nests". Control of the anchor lines is made possible where the determination of a localized stretch contributes to the determination of the effective length and the maintenance characteristics of the cable / chain combinations of the anchor buried in a sea bed; the determination of the net traction on the anchor-chaining combination, and the precise determination and localization of the stretching effects for feedback on a tensioning system. For stretched line and underwater mooring applications, the present invention provides an ability to separate the load and stretching effects induced by the movement of surface waves from those induced by oceanic bottom currents.

 It is therefore an object of at least some preferred embodiments of the present invention to provide new, unique, useful, non-obvious and efficient facilities and systems for well drilling cables with optical fibers to one or more Bragg gratings, cables provided with such fibers, and methods of implementing such installations or systems for determining the length of a cable in a well, the temperature at a point in the well, and tension on an organ in the well.

 Such cables include a metal tube incorporating an optical fiber freely disposed inside, which can be either an optical fiber with one or more Bragg gratings, or an optical fiber without a network; such systems are provided for measuring a static offset and a dynamic offset of the wave of a Bragg grating.

 Certain embodiments of the invention are not limited to such a particular individual characteristic presently described, but include combinations of these, distinct from the prior art by their structures or their functions. The features of the invention have been widely described so that the following detailed descriptions can be better understood, and so that the contributions of the invention to the art can be better appreciated. There are of course secondary aspects of the invention described below which can be included in the subject matter of the claims. Those skilled in the art who will benefit from this invention, its teachings, and its suggestions will appreciate that the concepts currently disclosed may be used as a creative basis to design other structures, methods, and systems for carrying out and putting into practice. the present invention. The claims should be read to include any legally equivalent device or method which does not depart from the spirit or scope of the present invention.

 A more specific description of the embodiments of the invention summarized above can be made with reference to the particular embodiments which are illustrated in the drawings, which form an integral part of the description. These drawings illustrate certain preferred embodiments and should not be used to inappropriately limit the scope of the invention which may have other embodiments which are also effective and legally equivalent.

 Fig.îA is a cross-sectional view of a prior art logging cable; Figs. 1 B and 1 C are cross-sectional views of the cable in FIG. 1A.

 Fig.2A is a cross-sectional view of a prior art logging cable; Fig.2B is a partial side view of the cable of Fig.2A.

Fig.3A is a schematic side view of an installation according to the present invention; Fig.3B is a schematic illustration of a signal processing method usable with the installation of Fig.3A; the
Fig.3C is a schematic illustration of a signal processing method usable with the system of Fig.3A; Fig.3D is a schematic side view of an optical fiber device according to the present invention.

 Fig.4 is a cross-sectional view of a logging cable according to the present invention.

 Fig.5 is a cross-sectional view of a logging cable according to the present invention.

 Fig.6 is a graphical representation of a filter output in a method and installation according to the present invention.

 Fig.3A illustrates a system S according to the present invention, which incorporates a line W comprising an optical fiber shaped as Bragg grating fiber ("FBG") at specified intervals (for example spaced about 1 to 20 meters or more), encased in a waterproof gangue in sili conetTéflonO / TefzelS and with an outer layer of steel reinforcing wires analogous to the "steel-light" cable manufactured by Rochester Co. placed in the center of the line (for example, in place of the central conductor of the lines shown in Fig.îA and 2A). The line extends from the ground surface into a cased well L.

Each FBG of the fiber has a unique wavelength (for example any suitable wavelength, and in certain preferred embodiments ranging between about 780 and 1650 nanometers) whose value is sufficiently far from the length waveforms of other FBGs to facilitate detection. The fiber optic fiber is connected to a coupler, for example a 2: 1 C coupler (for example a device 50 150 FO 3662 from Litton Polys cientific Co). The coupler is interconnected via an isolator I to a broadband source B, by way of nonlimiting example to a light source or to a source
Tunable laser, which can emit signals in a relatively wide spectrum of wavelengths, for example any suitable wavelength and in certain preferred embodiments, but not limited to, between 780 and 1650 nanometers.

 A detector system D in communication with the optical fiber O, via the coupler C detects the signals reflected from the FBGs, and measures the difference in the waves coming from them.

 To allow a voltage-free measurement of the temperature at the location of an FBG, one, or at least one, optical fiber with FBG is freely placed inside a stainless steel T tube in place of another conductor outside the line (see for example Fig. 3D). The stainless steel T tube is sheathed with copper twists so that it can also be used as a conductor. In this way, it is possible to replace several conductors.

 Fig.3C illustrates a system 200 which measures voltages and temperatures in different ways with one or more cables according to the present invention. The system 200 includes a computer 210 which can be interconnected with various subsystems and which, via the line 212, controls an optical switch 202, for example a 3x1 SR 1212 model from JDS-Fitel Co.

The reflected returns from the optical fibers of the well provided with FBG are transmitted through a fiber 250 to the switch 202. To measure the variation due to the stretching of the cable, of the Bragg wave of a Bragg grating of a optical fiber, a subsystem comprising a Fabry-Perot filter is used. This subsystem is particularly suitable for the treatment of a constant offset of a wave of
Bragg. The subsystem measures with an interferometer 206 the dynamic offset of a Bragg wave and it is particularly suitable for detecting such an offset induced by an acoustic signal, for example as transmitted by the acoustic transmitter A of FIG. 3A. The subsystem, thanks to a peak detector, detects the signal arrival time and is therefore particularly suitable for measuring cable lengths, for example the length from the surface to a particular FBG of the cable. As shown in Fig.3B, the peak detector 254 can be positioned between the Fabry-Perot filter and the mixer. The computer 210 controls, via a line 214, a signal generator 216 which produces a ramp signal intended to be mixed, thanks to a mixer 218, with a signal from a Fabry-Perot filter 204 for transmission. to the Fabry-Perot filter 204 after summing with a fluctuating signal thanks to a summing device 224. A fluctuating signal at high frequency is produced by a device 226. An optical fiber 228 connects the Fabry filter
Perot 204 to a receiver or detector 230 which converts the optical signal into an electrical signal. A line 232 connects the detector 230 to the mixer 218. By summing the fluctuating signal by scanning with the ramp-shaped signal, it facilitates the detection of the deviation, or of the offset, of the FBG wave. A mixed electrical signal from the mixer 218 is sent to a low-pass filter 234 which derives the signal and sends the derivative signal over a line 236 to a zero point crossing detector 240 which processes the derivative signal from the filter 234. The zero crossing detector defines the wavelength of the signal and, in the presence of the wavelength of
Bragg known, determines the deviation from the latter. An electrical signal from the zero point crossing detector, representative of a deviation from a Bragg wave of an FBG and indicative of stretching under load, for example, of a drilling cable, is sent to computer 210 via line 242. A mixer 218 amplifies the signal.

 When the switch 202 is in an appropriate position, the reflected returns from the FBG of the well are sent through the optical fiber 222 to a receiver 252 (analogous to the receiver 230) which transforms the optical signal into an electrical signal which is sent to a peak detector 254 across a line 256. The peak detector decides whether sufficient light energy is reflected back. If so, the peak detector 254 sends a signal to the computer 210 indicating that a reflection is present. The computer uses the signal to calculate the arrival time, that is to say a time t necessary for a signal to go to an FBG and return to the sensor, for example the time to cover a known "go" distance from where d = t / 2c, and t is the time of the round trip.

 The fiber conduits 233 route the light reflected from the well FBG, when the switch 202 is in an appropriate position, to an optical interferometer via an optical coupler 260. The interferometer transfers the light input into the filter 223 for transferring the light into an optical fiber 264. The outgoing light has a phase indicative of the wavelength of the input light. A coupler 262 connects the interferometer to the optical fiber 264 which is itself connected to a phase detector 266 which transforms the phase of the outgoing light signal into an electrical signal representative of the input wave. This signal is then sent to computer 210 via line 268 and the computer calculates the dynamic shift of the wave. A door opening time signal from the computer 210 is transmitted through a line 270 to the phase detector 266. This door opening time signal commands the phase detector 266 to work on signals from 'a selected FBG group. This limits the number to the number of FBGs, so that sufficient time is available for calculation and detection.

 Three measurement channels are therefore multiplexed at the same time by the optical fiber switch 202 (for example an optical switch from Dicon Co.) which switches between the optical fibers 221, 222 and 223. Alternatively, the switch can be eliminated and three other fibers connected simultaneously to fiber 250. The first measurement scheme uses the tunable Fabry-Perot 204 fiber filter and is suitable for measuring the voltages and the temperature in each FBG of a conforming optical fiber to the present invention (described in detail below). The second measurement scheme uses the unbalanced asymmetric interferometer 206, and is suitable for measurements of a dynamic shift of a wave, as described below. The third measurement scheme, described in detail below, uses the information transfer time to measure the distance from the departure of the fiber at the surface to each FBG. Thus the total length of line deployed in the well can be calculated by the combination of these measurements.

Localized measurement of temperature and voltage
A method for the localized measurement of temperature and tension in accordance with the present invention uses the data generated linked to the offset of a Bragg wave coming from each of the various FBGs, and gives both the static and dynamic forces imposed on the cable on each FBG. The measurands (quantities subject to measurement) include voltage and temperature. The surface detector system (Fig. 3A and 3B) use the reflected FBG returns transmitted by the line 250 and the Fabry-Perot filter 202. The output of the filter 202 is derived by the low-pass filter 234 to give a signal 235 as shown in
Fig. 6. This derivative signal is supplied to the zero crossing detector 246 which provides the offset 236 of an individual Bragg wave from each FBG, which offset expresses the voltage on a particular Bragg grating fiber. An extension of this system by division, or division multiplexing, of the time to be used for larger numbers of FBGs, also falls within the scope of the present invention. The offsets 237 express the effects of variations in sound pressure.

Since temperature and deformation affect a
FBG in much the same way, an additional measurement is necessary to distinguish between these two measurands. An additional FBD fiber wound in a helix and housed freely, (i.e. without tension, without stretching and protected from the stresses exerted on the cable) in a stainless steel tube (see Fig. 3D) replaces the 'one of the external conductors (for example see the external conductors in the cables of Fig.1A and 2A and 4).

 As shown in FIG. 4, a line 100 comprises a plurality of external steel reinforcement wires 104, a plurality of internal steel reinforcement wires 108, an internal sheath 106 (by way of nonlimiting example a conductive braid high temperatures), an interior filling 130 (for example TefzeI) coating the copper conductors 112, stainless steel tubes surrounded by a copper conductor 113, optical fiber fibers 120 comprising FBGs equally spaced over their length, and an insulating interior material 122 containing steel reinforcing wires 125 and an optic 126 comprising a plurality of FBGs distributed equally over its length. To allow a precise correlation between the temperatures of two fibers 120 and 126, the line 100 is constructed, in a particular form, such that an FBG 127 of the central fiber 126 and a FBG 129 of the outer fiber 120 are on the 'axis of the line, in axial positions, substantially identical (see for example Fig.3D). The spaces 130 can be filled with cotton ribbons coated with insulating paste.

 The surface system of Fig.3A can be used for the central fiber. Another surface system for the external fibers 120 is the same, except that a Fabry-Perot filter system is used there. The strand angle of the outer conductor and the outer diameter of the stainless steel tube are large enough for the fibers 120 to remain free, i.e. the fibers experience little or no tension, or stretching. For example, when the strand angle of the outer conductor is 200, the inside diameter of the stainless steel tube is 0.023 inch (0.58 mm)), the outside diameter of the fiber is 0.00295 (0.074 mm), the center of the stainless steel tube is at a distance of 0.0995 inch (2.52 mm) from the center of the line 100, the line can be stretched 0.95% without tension for the fibers 120 ( assuming that the fibers 120 are actually located in the center of the stainless steel tube provided that this tube is free of stresses at room temperature). Under this condition of absence of tension, the indications coming from the FBG of fibers 120 are used to measure the only temperature. These temperature indications are used in conjunction with the indications coming from the FBGs of the central fiber, to obtain a localized line tension, calculated by known methods (for example as in "Fiber optic Bragg grating sensors," Morey et al, SPIE Vol. 1169, Fiber optic Laser Sensors Vll, 1989, pp. 98-107; and in "3M Fiber Bragg Grating Application Note," February 1996). This method provides the voltage located on a line cable as well as the temperature undergone by the line. Such measures would not have been possible with the magnetic marker cables on the market.

 Fig.5 shows a component 150 of central fiber of the prior art similar to the central element housing the fiber 126 of Fig.4, but with an outer jacket 152 in KynartE) surrounding a glass-epoxy composite 154 which itself surrounds an inner jacket 156. The inner jacket 156 contains three optical fibers 160 each comprising a plurality of equally distributed FBGs. The fibers 160 are arranged in a coating, for example of the silicone RW 164. When the outer jacket 152 is made of a rigid material, for example of rigid KynarE, the fibers of the center are therefore protected from the pressure of the well.

Example: temperature and voltage measurement
The effects of temperature and voltage on the offset of a Bragg wave are modeled in the aforementioned 3M notice, by an equation, on page 4 thereof.

A 3M fiber has the following characteristic values
A b = 0.79 g + 613 x 104 AT
where AT is in OC. These values could also be determined experimentally for an arbitrary fiber comprising an FBG.

Suppose that a first FBG of an external fiber (such as fiber 120, Fig. 4) has a lgb = 1.22 nm at kb = 1552 nm (Xb is measured at the surface temperature of 25 "C) Since = 0, for this external fiber: ## b / # b = 6.3 x 10-6 #T AT = (1.22 / 1552) x (1/613 x 104) = 125 C
For a second FBG in the center (for example fiber 126, Fig. 4) at the same position as the above-described FBG, it measures an ABb = 4.9 nm, 4.9in = 0.79s + 1.22 / kb
3.68 / 1552 = 0.79 E i.e. = 0.003 = 3%
The above measurement therefore indicates, at the location of the FBG, a well temperature of 250C + 1250C = 1500C, and a line tension of 0.3%.

Line length measurement
An acoustic transmitter A (see Fig.3A) is positioned on the surface E of the ground above the well L. As the line
W passes through this transmitter, the acoustic signal sent by transmitter A is perceived by an FBG which passes through it. Using the Doppler effect, we can calculate at what precise moment the FBG is passing through the transmitter. When the FBG is above the transmitter and moves towards it, the detected acoustic frequency is slightly higher than that transmitted. When the FBG is below the transmitter and moves away from it, the acoustic frequency is slightly lower than that transmitted. In a particular case, in order to increase the efficiency of the energy transfer from the transmitter to the FBG, the medium between the transmitter and the line is replaced by a hollow solid above the well through which the line slides when she goes down into the well L
An FBG is able to measure the pressure variations in the well in terms of acceleration, emitted by the acoustic transmitter A.

This variation in pressure results in a dynamic variation in the difference in the Fabry-Perot light wavelength in the returns reflected from an FBG.

Although the measurement scheme implementing what is described above also provides dynamic variation of the wavelength, the scheme described below is suitable for measuring the dynamic shift of the wavelength. This measurement scheme uses an asymmetric interferometer 206 which translates the dynamic shift of the wavelength into phase difference, which in turn is translated into an acoustic signal which identifies the particular FBG entering or leaving the well L. A door open time signal from computer 210 is used to restrict the measurement to a single FBG at a given time. A previous known position of the line as well as the direction of its movements allows the computer 210 to determine which is the next FBG which will enter the well L, thereby making it possible to calculate the door opening time. Alternatively, the computer selects a search mode by which the measurement is carried out on the subset of FBG entering or leaving the well. The subset of
FBG contains one of all the FBGs in line W. In some cases, the search mode is only used occasionally since it takes relatively more time to acquire than to measure. According to an embodiment in which a central fiber is not housed in a tube in a relaxed manner, the FBGs of this fiber take up more acoustic energy and this search mode is used in this measurement scheme. Again, this measurement also involves sending a pulse from a broadband source B into the central fiber. After identification of
Particular FBG which crossed the acoustic wave field, the journey time is calculated from this FBG, for example by a high speed clock, not shown, of the counter 210. This crossing time, together with knowledge of the total line length, provides, after appropriate temperature correction, the line length inside the well. This journey time is measured according to another measurement scheme; in this scheme the pulses are transmitted from source B with a broad spectrum. The duration of the pulse is short enough to allow separation of the reflected returns from neighboring FBGs. For example with an interval between two neighboring FBGs of 25 m, the maximum pulse duration is (25) (2) (n) / c = 250 ns, where n is the refractive index and is equal to 1, 5 (for example) and c the speed of light in a vacuum. In practice, a pulse is transmitted whose duration is much shorter than the maximum value of 250 nanoseconds.

To measure the total length of line W, a
FBG is placed at the end of the line or in the head of a "torpedo" cable. The crossing time until the last FBG provides the total length of the line. In another way, the known OTDR ("Optical Time Domain Reflectometer") method of measuring the reflection from an abrupt termination (for example breaking of the fiber) at the head of the torpedo cable is used to obtain the total length of the line.

Example: measuring a line length
Let t2 be the duration of the "round trip" journey from the surface end of a fiber (for example fiber 126, Fig.4) to the bottom end of the fiber. Let ta be the round trip time from the surface end of the fiber to an FBG which passes just in front of an acoustic signal generator (as in the system in Fig.3A). Suppose that the measure of t2 is 32.08 s and the measure of t1 is 2.90 s. Consequently, the total duration of the round trip which concerns the portion of the line which is deployed in the well, is equal to t2 - t1 = 29.18 closed. Let L be the line length that is deployed in the well. Let L0 be the total length of the line (including the surface portion of the soil).

Since temperature affects the refractive index,
The effect of this temperature is corrected by calculating the length of the line using the measured round trip time. Let T2 = 1500C the temperature measured by the
FBG at the end of the well, and T1 = 250C the surface temperature. The refractive index at the bottom of the well is
n2 = n0 [1+ (dnldT) x (T2 - T1)] where nO = 1.45 is the refractive index at T1 = 250C at the surface. dnidT for the fiber is equal to 1.0x10-5 C-1.

Therefore:
n (L0) = 1.45x [1 + 1.0 x 10-5 X (150-25)] = 1.4518
To simplify the illustration, it is assumed below that the geothermal gradient varies linearly with the depth and that the well is vertical. Therefore, we can show that
trti = 2naLlc where c = 2.9979 x108 mls is the speed of light in a vacuum, and na is the average refractive index of the fiber inside the well. This average is equal to:
na = n0 + n2 / 2 = (1.45 + 1.4518) 12 = 1.450
Therefore, from the equation for t2-t1.

29.18x10 = (2 x 1.4509 x L) / 2.9979 x 108
L = 3,014.6 meters
Consequently, the end of the line is at a depth of 3,014.6 meters measured from the position of the surface acoustic generator.

The total length of the line, in this state, under load is: Lo L + (2.90x 104xC) / 2xnO = 3.014.6 + 299.8
= 3.314.4 meters.

 The geothermal gradient contributes to L for a difference of 0.0625% This difference is equivalent to a length of 1.9 meters.

 In conclusion, it can therefore be seen that the present invention and its embodiments described above, as well as those defined by the appended claims, are well suited to achieve the objectives and obtain the results set out above. Certain modifications may be made thereto without departing from the spirit and scope of the invention. It should be considered that modifications may occur within the scope of the invention and it is understood that each element or step used in any of the claims which follows must be understood as relating to any equivalent element or step. The following claims are intended to cover the invention as broadly as is legally possible in whatever form they are used.

Claims (7)

CLAIMS 1 - Cable device, in particular intended for the control of wells, characterized: in that: said cable device (100) having spaced ends comprising a first and a second end, the well logging operations comprising operations of measuring the tension of the cable, its length and its temperature, the cable device incorporates at least one optical fiber (120,126) which extends from the first end of the latter to the end, and in that said otic fiber at least incorporates at least one Bragg grating (127,129); 2 - Device according to claim 1, characterized 1 characterized: in that said fiber is one of the fibers of a plurality of optical fibers (120 and 126);  3 - Cable device according to claim 1, characterized:  in that the said Bragg grating at least is one  networks of a plurality of Bragg gratings (127 and 129); 4 - Cable device according to claim 1, characterized:  in that the cable device incorporates a plura  lity of reinforcing wires (104,108,128) arranged around said optical fiber at least; 5 - Cable device according to claim 1, characterized:  in that the said plurality of optical fibers com  takes at least two optical fibers (120,126) spaced from each other, each  incorporating a plurality of Bragg gratings (127,129); (Fig.4) 6 - Cable device according to claim 6, characterized:  in that it comprises at least one metal tube  hollow (118) extending from the first end of the diagra cable device  phie to the second end,  in that said at least two optical fibers  spaced from each other and comprising at least a first optical fiber and at  at least a second optical fiber, the first optical fiber (120) is contained in a fa  at least relaxed in said hollow metal tube (118); 7 - Cable device according to claim 7, characterized:  in that the second optical fiber (126) is available  placed in said cable device in such a way that it lengthens when the cable  itself lengthens;  8 - Cable device according to claim 7, characterized  in that the hollow metal tube is made of stainless steel  oxidizable, and  in that the cable further comprises a plurality  copper cables (113,125) wound around the hollow metal tube (118), the  say twists extending from the first to the second end of the cable device; 9 - Cable device according to claim 8, characterized:  in that further an insulating material (130) is provided  placed between the first and second optical fibers;  10 - Cable device according to claim 1, characterized:  in that it comprises at least one conductive wire (112)  extending from its first to its second end; II - Device according to claim 13, characterized:  in that the hollow metal tube is steel in  oxidizable surrounded by a plurality of copper twists (113) which are understood to  first to second end of the cable device;  12 - Installation for operating a cable according to any one of claims  previous, characterized:  in that it includes:  - a control device, or system (S, 200),  - a wire line (W) provided with a vertex end and an end of  bottom, said line being connected to the system and comprising the wiring device  ble with its Bragg gratings (O),  - an optical coupler connected to the control system (S) and to said optical fiber  that (O) at least,  - a light source (B) connected to the control system (S) to send  a light signal in said optical fiber at least, and  - a detector (D) connected to the control device to detect a signal re  flexed from at least one Bragg grating; (Fig * 3A) 13 - Installation according to claim 12, characterized:  in that it further comprises an insulator (I) for  prevent reflected light from entering the source 14 - Installation according to claim 13, characterized:  in that it further comprises a transmitter  mobile acoustic (A) connected to the control device and located in the vicinity  of the wired line, and intended to transmit an acoustic signal to the said network of  Bragg running; 15 - Method for obtaining data thanks to an installation according to claim 14,  characterized:  in that it includes the steps of  to introduce said cable into a sinking well  in earth from the surface of the ground,  to send a signal through trans means  mission to at least a first Bragg network,  to receive the signal by means of reception,  and  processing the signal to obtain data;  16 - Method according to claim 15, characterized,  in that,  data including data relating to the  cable length between the ground surface and at least one of two networks  of Bragg, the said networks being spaced from each other by a distance d, a trans  acoustic transmitter being positioned in the vicinity of the cable so that an acoustic signal  that can be transmitted to and perceived by a Bragg network crossing the trans  acoustic transmitter, each network having an identification wavelength,  it further includes the following steps consis  so much:  to send an acoustic signal to the first network of  Bragg at a known location in relation to the acoustic transmitter and to be picked up  the wave of the Bragg grating, which derives therefrom, thus identifying the first Bragg grating,  and  to calculate the distance from the acoustic transmitter  until the second Bragg grating, based on the knowledge of the distance  d and the location of the first network; 17 - Method according to claim 16, characterized:  in that it further comprises the following steps  consisting of:  said first Bragg grating at least being one  of a plurality of networks spaced from each other, and a Bragg network terminated  nal being located at the lowest end of the fiber in the cable device,  to send a signal from a broadband source  through at least one optical fiber to the terminal Bragg grating, and  to be picked up, with a sensor placed at a distance  known from the Bragg network, a return signal from the terminal Bragg network  to the sensor, as well as the duration of the signal return path from the network  terminal up to said sensor, and  to calculate the length of the wired line of the device  cable from the sensor to the terminal network;  18 - Method according to claim 16, characterized:  in that it further comprises the following stages consisting,  the said Bragg grating at least having a length  wave identifier  to send an interrogation signal from a trans  fundraiser at the first Bragg network,  to receive the signal through a receiving device  reflected from the said network at least, and  to calculate the line voltage located on said re  Bragg bucket at least by determining the deviation from the network wavelength by  calculating the difference between the wavelength of the reflected signal and the length  network wave. 19 - Method according to claim 16, characterized:  in that it further comprises the following steps consisting:  said network at least having a single wavelength,  to introduce the cable and the network to a deep location in the well,  to measure the wavelength of the grating at this deep location,  calculating the wavelength difference between the single grating wavelength and the wavelength measured at the known deep location, and  to determine the temperature at said deep location of the well, using the calculated difference,