MXPA98007318A - Well cable, system and method of recording and data monitoring within a punch perforation - Google Patents

Abstract

The present invention relates to a cable for well drilling logging operations, characterized in that the cable comprises well drilling cable apparatus having separate ends including a first end and a second end, at least one optical fiber inside the well. Well drilling cable apparatus and extending therein from the first end of the well drilling cable apparatus to the second end thereof, and at least one fiber Bragg grating in at least one fiber optics.

Description

WELL CABLE MONITOR SYSTEM DESCRIPTION OF THE INVENTION The present invention is directed to the field of the armed cables used in the electrical recording of oil and gas wells and to the monitoring of the length of such cables, the detection of the temperature and the Tensions imposed on the cables. In a particular aspect, the present invention is directed to a monitoring system with one or more optical fibers with one or more Bragg-type fiber grids. The electric drilling log cables carry measurement instruments in the drilling holes in the ground which generate signals related to the physical properties of the land formations and make it possible to record the properties of the land formations at a plurality of depths within Well drilling. This is usually done by pulling the instrument out of the well bore, winding the log wire over a winch or similar winding device while the signals generated by the instruments are recorded and, therefore, a record of the measurements is made. . In certain systems of the prior art, the measurement of the depth of an instrument in a well borehole is made using a calibrated wheel placed in frictional contact with a cable. The calibrated wheel rotates correspondingly with the amount of linear movement of the cable passing the wheel as the cable is moved into or out of the well bore by the winch. In one aspect of a plurality of markers that are separated on a cable. The wheel may be rotationally coupled to a calibrated mechanical counter to indicate the length of cable moving past the wheel, or the wheel may be coupled with an encoder connected to a counter or computer to electronically indicate the length of cable that is moving past the wheel. Such wheels can accurately determine the total cable length that is moved by passing the wheel into the well bore although the true depth of the instrument in the borehole may not correspond exactly to the total length of the moving cable. passing the wheel because the cable is subjected to stretching when the tension on the cable varies. Both the temperature and the weight affect the tension on the cables. The total weight of a cable placed inside a well bore can be as much as 226.5 kg (500 pounds) per 304 meters (1000 feet) of cable, the instrument itself has a significant weight when inserted into the borehole. Well, which can vary depending on how large is the volume of the instrument that is enclosed in the air space and the density of a fluid in the well drilling. The measurements made by the instrument may have been made at depths of 6.8 meters (twenty feet) or more than the depth indicated by the calibrated wheel due to the stress induced by stretching in the cable as the instrument is pulled from the wellbore. The least predictable parameter that affects the tension of the cable is friction, which can increase the stretch on the cable as it moves in and out of the wellbore because the wall surface of the wellbore has a non-working grade. Known roughness and ground formations penetrated by well drilling have unknown friction coefficients. The drilling mud or fluid in the well borehole can vary the viscosity at different depths within a particular well bore making it more difficult to determine the effects of friction. U.S. Patent No. 4,803,479 to Graebner et al. Discloses a method of depth measurement to compensate for the amount of stretching in the cable that includes making a measurement of a displacement in the phase of an electrical signal sent through the cable. all the cable and returned to the equipment on the surface of the earth, the phase shift measurement related to the phase shift of the same electrical signal sent through a reference wire placed on the ground surface that has invariable length. In the Graebner patent method, the phase shift in a constant frequency electric signal depends only on the change in the signal transmission time, so that the phase shift corresponds to a change in the length of the signals. electrical conductors _on the cable. One limitation of the method of Graebner et al., 79 is that the change in the length of the electrical conductors in the cable may not correspond exactly to a change in the length of the cable. The electrical recording cable typically comprises a plurality of insulated electrical conductors, covered by helically wound steel reinforced cables. A recording cable typically comprises seven conductors, six of the conductors that are wound helically around the seventh conductor. When such a multiple conductor cable is stretched, part of the stretch is consumed by the unwinding of the helically wound conductors, so that the length of the cable increases more than the length of which the helically wound conductors increase.

Another limitation of the method described in the M79 patent of Graebner et al., Is the ratio of change in cable length to phase shift of the electrical signal, known as the scale factor to be determined for each particular cable since the properties Electrical signal transmission may vary in some way between different cables. An additional limitation of the method described in the 79 patent of Graebner et al., Is the need to use an additional conductive medium on the ground surface to provide a fixed length phase reference for comparison of the phase change in the recording cable. . A substantial length of the cable can be used as a fixed length reference that can occupy a significant storage space which may not be practical. Frequently, small cable lengths are cut such as 30.4 to 91.20 meters (100 to 300 feet) from the end of a particular cable that is lowered into the well bore as the end of the cable wears or becomes damaged. In other circumstances, the cable is cut in order to retrieve an instrument that has been stuck in the well bore, the cut wire is later reassembled by splicing. When a cable is cut, the scale factor may have to be determined again by imparting a known amount of stretching to the cable and measuring the phase shift caused by the known stretch. It is difficult to recalibrate the scale factor at the location of the well bore since the equipment intended to impart a known stretch to the cable typically can only be located at a specialized facility. The system of U.S. Patent 4,803,479 is also deficient in that the accuracy of the phase shift measurement is rapidly reduced with the increase in the frequency of change in the length of the cable. The highest frequency changes in the amount of cable stretch can be caused by the "adhesion-tilt" movement of the logging tool since the combination of gravity and friction of the hole bore momentarily exceeds the upper traction of the logging cable, only to be violently released in a spring-like movement according to the frictional force is overcome when the upper tension of the cable accumulates sufficiently. U.S. Patent No. 3,490,149 for Bowers describes a method of determining the depth of logging tools in a well drilling. The system includes an accelerometer to measure the acceleration of coaxial logging tools with well drilling. The acceleration measurements of the coaxial logging tools with the hole hole are double integrated to provide a determination of change in the axial position of the logging tools. The change in the axial position determined from the doubly integrated accelerometer measurements, are used to adjust the measured position of the tool as determined by measurements of the amount of cable that has passed a device to measure the amount of cable that it extends into the well borehole. A disadvantage of the system is that doubly integrated acceleration measurements typically must be band-limited by a filter to remove direct current, and a very low frequency AC output from the accelerometer to correct "the variation in zero reference" (also known in the art as constant systematic error). If the acceleration of the tool descends to a filter cutoff frequency then the low frequency accelerations on the tool can be caused by forces such as friction, which change the tension force, and therefore the length of the cable, may not be detected. Therefore, the system is only useful for correcting depth measurements for higher frequency accelerations on the logging tools. U.S. Patent No. 4,545,242 to Chan discloses an improvement in the method described in Bowers Patent x149. The system includes feedback amplifiers to decrease an error signal generated in the process of integrated accelerometer measurements to determine the actual position of logging tools in well drilling. This system has the limitation that there is substantially no system response below the lowest cutoff frequency of a filter applied to the output of the accelerometers. The systems described in the Patent 149 of Bowers and the 242 of Chan are not able to provide accurate depth information thereon, each of which the electric wire is "extended" at frequencies below the filter cut applied to the accelerometer. Methods that involve the reading of magnetic markers have several disadvantages: 1) the accuracy of the magnetic markers decreases with use and time, and therefore the position accuracy of the markers also decreases; 2) periodically the markers need to be remagnetized due to the loss of magnetism with use and time; 3) the length of the perforation cable between the magnetic markers, assumed as fixed, is only approximately fixed and the perforation cable extends with use and therefore the length between the markers increases; and 4) the slip is induced by the friction measuring wheels, particularly in wet drilling cables and / or drilling cables coated with drilling fluid while coming out of a drilling hole. Several known armed electrical cables have one or more insulated electrical conductors that are used to supply electrical power to the well recording instruments and to transmit signals from the instruments to the equipment on the ground surface for signal processing. These cables have steel disassemblies wound helically around the electrical conductors to provide torsional strength, tensile strength and abrasion resistance. A variety of known prior art recording cables have optical fibers and use optical telemetry at high frequencies and at higher data transmission rates than those of electrical signal transmission. Known prior art cables have optical fibers enclosed in a steel tube. Another combination of prior art fiber optic / electric well logging cable has an optical fiber encased in a steel tube in the center of a well logging cable with conductive members externally positioned to a central tube containing the fiber Optical and constructed of copper-plated steel cable. Another type of combination of the prior art fiber optic / electric well logging cable has an optical fiber coated with plastic instead of one or more electrical conductors. A combination of the prior art fiber optic / electric well logging cable technique includes an optical fiber encased in a metal tube surrounded by braided copper strands to conduct electrical power and electrical signals. U.S. Patent 5,495,547, co-owned with the present invention, discloses a combination of fiber optic / electric conductor well log cable. This patent describes the problems associated with the prior art cables described above and the patent is hereby incorporated in its entirety for all purposes. As shown in Figure 1A, U.S. Patent 5,495,547 describes, in certain embodiments, a well log cable that includes first elements that are a copper-plated steel wire surrounded by copper strands and covered with a material electrical insulator, and at least a second element that includes at least one optical fiber enclosed in a metal tube, copper strands that encircle the tube and covered by electrically insulating material. The first elements and at least one second element are placed in a central package. The second element is placed in the package to be wound helically around a central axis of the package. The package is surrounded by helically wound wires externally wrapped to the package. A cross section of such prior art well register cable 10 is shown in Figure IA and is described in U.S. Patent 5,495,547. The parts of the cable 10 are shown in Figures IB and IC. The cable 10 includes seven insulated conductor elements with plastic placed in a central package 15 having a substantially regular hexagonal pattern, where six of the elements surround the seventh element. The first elements 16 are, in one aspect, insulated electrical conductor elements that include a copper-coated steel cable of approximately 0.068 cm (0.027 inches) in diameter surrounded by nine copper wires, each approximately 0.0325 cm (0.0128 inches) ) diameter. The first elements 16 includes an outer insulation jacket composed of heat and moisture resistant plastic such as polypropylene or ethylene-tetrafluoroethylene copolymer ("ETFE") sold under the trade name "TEFZEL" which is a trademark of E. I. du Pont de Nemours & Co. The second elements 18 each include, among other things, an optical fiber placed in a stainless steel tube. The cable 10 includes two symmetrically placed second elements 18 which can be placed in any or all of the six locations placed externally on the regular hexagonal pattern formed by the seven elements. The hollow spaces within the hexagonal structure of the seven elements 16, 18, are in one aspect filled with a filler material 17, a plastic such as neoprene or ETFE. The filler 17 maintains the relative position of the seven elements 16, 18 within the cable 10. The elements 16, 18 and the filler 17 are covered with helically wound galvanized steel reinforced cables, formed in an internal reinforced lining. The internal reinforced liner 14 is externally covered therein with helically wound galvanized reinforced steel cables formed within an external reinforced lining. The internal reinforced liner 14 and the outer reinforced liner 12 are designed to provide significant tensile strength and abrasion resistance to the cable 10. In one aspect the cable 10 is intended to be used in a chemically hostile environment such as a borehole. well having significant amounts of hydrogen sulfide and the reinforced wires 12, 14 are alternatively composed of a cobalt-nickel alloy such as one identified by industry code MP-35N.

One of the second elements 18 is shown in more detail in Figure IB and consists of an optical fiber 22 enclosed in a metal tube 24 composed of stainless steel in order to provide corrosion resistance. The tube 24, in one aspect, has an outer diameter of 0.083 cm (0.033 inches) and an internal diameter of 0.058 cm. (0.023 inches). The tube 24 provides protection from abrasion and bending to the optical fiber 22, and excludes fluids in the wellbore from the cable. The tube 24 may be copper coated to reduce its electrical resistance and surrounded by 12 strands of copper wire shown generally at 26. The cable strands 26 may be 0.02 cm (0.01 inch) in diameter. The combination of tube 24 and strands 26 provides a conduit that has an electrical resistance of less than 10 ohms per 304 meters (1,000 feet) in length. The tube 24 and the copper strands 26 are further covered with plastic insulator 20 comprised of a heat resistant plastic such as ETFE, or polypropylene. The outer diameter of the insulator 20 in the second element 18 is substantially equal to the external diameter of the insulation of the first element 16, so that the hexagonal pattern of the seven elements as shown in the cross section of Figure 1A is substantially symmetrical, despite the relative position of the second element 18 within the hexagonal pattern of the package 15. The second elements 18 can be placed in one or any of the six external positions of the hexagonal structure as shown in Figure 1A. The second element 18 in one aspect can be placed in an external location on the hexagonal structure of the package 15 because the elements 16, 18 in the external locations are wound helically around the element in the central position. For reasons such as the lateral reduction in the mean diameter with the axial tension, the unwinding of the helical layer and the larger overall length of the external elements wound helically with respect to the length of the central element 18, the externally placed elements 16, 18 support the reduced axial tension in relation to the axial elongation of the cable thus reducing the possibility of failure induced by axial tension of the tube 24 and the fiber 22. The second elements 18, in one aspect, they are placed in two external locations opposite each other in the hexagonal pattern. Figure IC shows a cross section of a first element 16 in greater detail. The first element 16 has, in one aspect, a steel wire 28 plated or plated with metallic copper to have an end diameter of approximately 0.068 cm (0.027 inches), thereby reducing the electrical resistance of the cable 28. The covered cable with copper 28 it is further surrounded by nine copper strands, generally shown at 30 and having an outer diameter of 0.0128 cm (0.0128 inches). The combination of steel wire 28 and copper threads 30 have an electrical resistance of less than 7 ohms per 304 meters (1000 feet) in length. The strands 30 are covered with an electrical insulating material 32 such as polypropylene or PTFE. The second elements 18 are designed such that the combination of the tube 24 and the cable strands 26 have an outer diameter that allows the insulating material to provide the second element 18 with substantially the same electrical capacitance per unit length as the first element 16. The assembled cable will have substantially the same electrical power and the same signal transmission properties as other cables made in accordance with the prior art. U.S. Patent 5,541,587 co-owned with the present invention and fully incorporated herein for all purposes, discloses a system for determining the depth of a recording tool achieved up to an extended cable within a well borehole penetrating into a ground formation A particular embodiment of the system includes a circuit for generating a phase shift measurement in a sinusoidal electrical signal transmitted through the cable, the phase shift in the signal corresponds to the length of the cable. The system also comprises an accelerometer placed inside the tool and electrically connected to the band pass filter. A double integrator is connected to the bandpass filter. The double integrator is connected to the bandpass filter. The double integrator calculates the position of the coaxial tool with the wellbore. The phase shift measurement is passed through a low pass filter. The low pass filter and the bandpass filter comprise at least some degree of bandpass overlap. The output of the integrator is used to generate a scale factor that is applied or to the filtered phase shift measurement. In the measurement of scaled phase displacement is conducted to a depth computer as an arc of a signal generated by the depth encoder and integrated accelerometer measurements. The depth encoder signal corresponds to the amount of cable that extends into the well bore. The depth computer calculates the depth of the tool in the wellbore by adding the scaled phase shift measurements, the integrated accelerometer measurements and the encoder measurements. Figures 2A and 2B show the prior art cable described in U.S. Patent 5,541,587. The cable is a typical multi-conductor well log cable whose exterior comprises coiled, helically wound cables, made for example of steel. The electrical conductors inside the reinforced cables include a central conductor and external helically wound conductors. The center conductor is collinear substantially with the length of the cable and is substantially coaxial with the cable through its entire length. There has long been a need for a monitoring system for a well log cable that accurately indicates the length of the cable, the tension on the cable and / or the temperature at a cable location. The present invention, in certain embodiments, describes a system for accurately determining the length of cable or a drill string in a drill hole to thereby determine the location of an instrument on the cable in the drill hole and, therefore, , the location to which the instrument is activated to make the measurement. In one aspect, the system includes a cable, a multiple wavelength emitting source on the surface interconnected with the cable, the cable having one or more optical fibers as discussed below with one or more Bragg fiber grids, and a coupler that couples the optical fibers to the source.

Several advantages are achieved using the Bragg fiber grids. The grid is a permanent part of the drill string, that is, it is not easily removable like magnetic markers and does not need to be renewed like magnetic markers. The distance between two grids can easily be determined in real time with the proper instrumentation. The grids provide dual functions of temperature and voltage measurement. The replacement of the auto switch with the acoustic detector and the use of the Doppler effect provides much more accurate measurements. The grids can be applied to or formed into a fiber in a very controlled and precise environment. In one aspect of a system according to the present invention, a central cable conductor is an optical fiber with one or more gratings of Bragg fibers therein, formed therein, or some combination thereof. The or Bragg fiber grids have a unique Bragg wavelength with a value, in certain embodiments, sufficiently separated from the others to facilitate detection. In an embodiment in which such a system is used to separate the stress-free temperature measurement, two optical fibers are used, each of which has a plurality of separate gratings. One of the fibers is loosely placed inside a metal tube (for example steel or stainless steel) instead of one of the external conductors of a cable (for example, but not limited to a cable as in Figure 1A or Figure 1A). Figure 2A). The other fiber is placed in place of a central cable conductor (for example, but not limited to a cable as shown in Figure IA or Figure 2A). In another aspect the metal tube is stainless steel wrapped with copper strands and used as a conductor. One or more such conductors may be employed. The methods according to the present invention utilize systems as described herein which include methods for determining the temperature located in a well bore, methods for measuring the stress on a cable in a well borehole and methods for determining the length of a cable in a well drilling. The systems and methods according to the present invention are very useful in a variety of situations. When the logging tools and / or other devices of the bottom of the drilling are transported by means of drill pipe ("Log Transported by Pipe"), or by means of propulsion devices of the bottom of the mechanical drilling such as well tractors or tracked tractors, the ability of the present invention to determine the localized line voltage aids in the determination and location of the key settlement; determining the effective tensile strength at a high angle • and / or horizontal sections while dragging it outside the horizontal section or outside the hole; and determining the effective linear feed rate as long as it is trailed in and / or through the horizontal sections to avoid key settlement and / or "nesting". The control of the anchor lines is made possible when the determination of localized stretching helps in the determination of the effective length and maintains the characteristics of the anchor chain / cable combinations buried in the seabed; the determination of the net traction in anchor / anchor chain combinations; and the determination and precise location of the stretching effects for feedback to a tensioning system. For the recording of stress and toothed applications on the ocean floor, the present invention provides the ability to separate the effects of loading and stretching, induced by the movement of surface waves from the effects of the load and the Stretching induced by ocean bottom currents. Therefore, it is an object of at least some preferred embodiments of the present invention to provide new, unique, useful, non-obvious and effective systems with well log cables having optical fibers with one or more Bragg fiber grids and cables. with such fibers, and such systems useful in methods for determining the length of a cable in a well bore, the temperature located in a well borehole and the stress on a member in a borehole.; Such cables having a hollow metal tube with an optical fiber loosely placed thereon either an optical fiber with one or more Bragg fiber grids or without any such grids; and Such systems for measuring the stable displacement of measurement and the dynamic displacement of a Bragg wavelength or of a Bragg fiber grating. Certain embodiments of this invention are not limited to any particular individual feature described herein but include combinations thereof distinguished from the prior art in their structures and functions. The features of the invention have been amply described so that the detailed descriptions which follow may be better understood, and in order that the contributions of this invention to the art may be better appreciated. There are, of course, additional aspects of the invention described below and which may be included in the subject matter of the claims for this invention. Those of skill in the art having the benefit of this invention, its teachings and suggestions will appreciate that the conceptions of this disclosure can be used as a creative basis for the design of other structures, methods and systems for carrying out and practicing the present invention. . The claims of this invention are to be read including any legally equivalent devices or methods that do not deviate from the spirit and scope of the present invention. The present invention recognizes and addresses the previously mentioned problems and the long-considered needs and provides a solution to these problems and satisfactorily covers those needs in their various possible and equivalent modalities thereof. For someone skilled in the art who has the benefits of these embodiments, teachings, descriptions and suggestions of the invention, other purposes and advantages will be appreciated from the following description of the preferred embodiments, given for the purpose of description, when take along with the attached drawings. The detail in those descriptions is not intended to impede the object of this patent to claim this invention which is not a matter of, as others may later distinguish, its variations in form or additions for further improvements.

BRIEF DESCRIPTION OF THE DRAWINGS A more particular description of the embodiments of the invention briefly summarized in the foregoing, can be had by reference to the modalities shown in the drawings which form part of this specification. These drawings illustrate certain preferred embodiments and are not used to improperly limit the scope of the invention which may have other equally effective or legally equivalent modalities. Figure IA is a cross-sectional view of a well log cable of the prior art. Figures IB and IC are cross-sectional views of the cable parts of Figure IA. Figure 2A is a cross-sectional view of a well registration cable of the prior art. Figure 2B is a partial side view of the cable of Figure 2A. Figure 3A is a schematic side view of a system according to the present invention. Figure 3B is a schematic view of the signal processing method useful with the system of Figure 3A. Figure 3C is a schematic view of a useful signal processing method - with the system of Figure 3A. Figure 3D is a schematic side view of an optical fiber system according to the present invention.

Figure 4 is a cross-sectional view of a well registration cable according to the present invention. Figure 5 is a cross-sectional view of part of a well log cable according to the present invention. Figure ß is a graphic representation of an output of a filter used in a system and method according to the present invention. Figure 3A illustrates an S system according to the present invention having a drill wire W with an optical fiber or with construction in fiber grids Bragg ("FBG" ") at specific intervals (for example between approximately 1 and approximately 20 or more meters apart) embedded in an airtight Silicon / Teflon ™ / Tefzel ™ damper and with an outer layer of steel reinforced cables such as cable light steel manufactured by Rochester Co. A single fiber element is, in one aspect, placed in the center of the drill string (for example in place of the center conductor of the drill wires shown in Figures 1A and 2A).

The drill string extends from an E ground surface into an enclosed well bore L. Each FBG in the fiber has a wavelength Single Bragg (for example any suitable wavelength and in certain preferred embodiments ranging from about 780 to 1650 nanometers) whose value is sufficiently separated from the wavelengths of the other FBGs to facilitate detection. The optical fiber is connected to a coupler, for example, a 2: 1 letter C coupler (for example a 50/50 FO 3662 device from Litton Polyscientific Co.). The coupler is interconnected by means of an insulator I to a broadband source for example but not limited to a light source or a selectable laser B which can emit signals in a relatively large spectrum of wavelengths, for example any length of wave and in certain preferred embodiments, although not limited to, between 780 nanometers and 1650 nanometers. A detector system D in communication with the optical fiber O, by means of the coupler C detects: signals reflected from the FBG; and measures the wavelength deviation from a Bragg wavelength of the FBGs. To allow a voltage-free measurement separate from the temperature at the FBG location, an optical fiber (or at least one optical fiber) with the FBGs is loosely placed inside a stainless steel tube T that replaces another external conductor in the drill string (for example, see Figure 3D). The stainless steel tube T is wrapped with copper strands D so that it can also be used as a conductor. Several drivers can be replaced in a similar way. Figure 3C shows a system 200 that measures stresses and temperature in a variety of ways with a cable or cables according to the present invention. The system 200 has a computer 210 interconnected with the different subsystems and that, by means of the line 212, controls an optical switch 202, for example a model 3 x 1 SR 1212 of JDS-Fitel Co. The returns reflected from the optical fibers of the hole drilling with FBG are transmitted through a fiber 250 to switch 202. To measure the deviation due to stretching of the cable at the Bragg wavelength of a Bragg fiber grating on an optical fiber, the subsystem including a Fabry-Perot filter 204 is used. This subsystem is particularly suitable for dealing with a stable deviation in the Bragg wavelength. The subsystem with an interferometer 206 measures the dynamic shift at the Bragg wavelength and is particularly suitable for detecting such displacement induced by an acoustic signal, for example when it is transmitted by the acoustic transmitter A in Figure 3A. The subsystem with a peak detector 254 detects the arrival signal time and is therefore particularly suitable for measuring the length of the cable, ie the lengths of the surface up to a particular FBG on the cable. As shown in Figure 3B, the peak detector 254 can be positioned between the Fabry-Perot filter and the mixer. By means of a line 214, the computer 210 controls a waveform generator 216 which produces a ramp signal to be mixed with a signal from a Fabry-Perot filter 204 with a mixer 218 and for transmission to the Fabry-Perot filter 204 after being summed with a takeoff signal by a summing device 224. A high frequency takeoff signal is produced by a device 226. An optical fiber 228 connects the Fabry-Perot filter 204 and a receiver (or detector) 230 which converts the optical signal to an electrical signal. A line 232 connects the receiver 230 to the mixer 218. By adding the takeoff signal with the ramp signal of the scanning waveform, detection of the change in wavelength of FBG is facilitated. An electrical signal mixed from the mixer 218 is transmitted to a low pass filter 234 that differentiates the signal and sends a derivative signal on a line 236 to a zero crossing detector 240 which processes the differentiated signal from the filter 234. The zero crossing defines the signal wavelength and, with the known Bragg wavelength, determines the deviation from the Bragg wavelength. An electrical signal from the zero crossing detector representative of a deviation from a Bragg wavelength of FBG and indicative of, for example, stretching (loading) on a well drilling wire is sent to computer 21Q on line 242 A mixer 218 multiplies the signal. With the switch 202 in the proper position, the reflected returns from the FBG wellbore are fed into the fiber 222 to a receiver 252 (similar to the receiver 230) which changes the optical to electrical signal and then sends an electrical signal towards a peak detector 254 on a line 256. The peak detector 254 decides whether sufficient light energy is reflected. If so, the peak detector 254 sends a signal to the computer 210 that indicates that a reflection is present. If the computer uses the signal to calculate the arrival time, for example, a time t for a signal that goes to the FBG and then returns to a sensor, that is, it covers a distance in a known direction d where d = t / 2c, and t is the displacement time in both directions. The fiber 223 conducts the reflected light returns from the wellbore FBG when the switch 202 is in the proper position towards aninterpreter 206 by means of an optical coupler 260. The interferometer transfers the input light in the filter 223 to the output light on an optical fiber 264. The output light has a phase indicative of the wavelength of the input light. A coupler 262 connects the interferometer to the optical fiber 264, the which is connected to a phase detector 266 which transforms the phase of the output light signal to an electrical signal indicative of the wavelength of the input light. This signal is then sent to computer 210 on line 268 and computer 210 calculates the dynamic offset at the wavelength. A time gate signal from the computer 210 is transmitted on a line 270 to the phase detector 266. The time gate signal indicates the phase detector 266 to work on the signals of a selected set of FBG. This limits the number of FBGs so that there is enough time available for calculation and detection. Three different ways of measuring are, therefore multiplexed in time by the fiber optic switch 212 (for example a Dicon Co. optical switch) that the switches between the optical fibers 221, 222 and 223. Alternatively, the switch can be removed and the three fibers connected to each other. the fiber 250 simultaneously. The first measurement scheme uses the selectable fiber Fabry-Perot filter 204 and is suitable for measuring the stretching and temperature in each FBG in an optical fiber according to the present invention (described in detail below). The second measurement scheme uses the unbalanced asymmetric interferometer 206 and is suitable for measuring a dynamic shift in the wavelength, as described below. The third measurement scheme, described in detail below, uses the displacement time information to measure the length from the beginning of the surface drilling cable to each FBG. Therefore, the total length of the drilling cable deployed in the well drilling can be calculated by combining those measurements. Localized Temperature and Voltage Measurement A method for localized temperature and voltage measurement according to the present invention, uses the data generated in relation to the deviation from the Bragg wavelength for each of the different FBGs and gives the static and dynamics imposed on each FBG. The measurements include the voltage and -the temperature. The surface sensing system (Figure 3A and 3B) uses reflected FBG returns transmitted via line 250 and the Fabry-Perot 202 filter. The output of the filter 202 is differentiated by the low pass filter 234 to give a form of wave as shown in Figure 6. This differentiated signal is fed into the zero crossing detector 246 which obtains the deviation from the individual Bragg wavelength for each FBG indicating the voltage on a particular fiber Bragg grid. The expansion of this system that uses time division multiplexing to be used for larger amounts of FBG is also within the scope of this invention. Since temperature and voltage affect an FBG in roughly the same way to distinguish between those two measurements, an additional measurement is needed. An additional fiber that accumulates in helically wound and loosely enclosed FBG (for example tension-free, stretch-free and isolated from the tension on the cable) in a stainless steel tube (see Figure 3D) Replaces one of the external cable conductors (for example see the external conductors in the cables of Figures A, 2A, and 4). As shown in Figure 4, a drill string 100 has a plurality of steel reinforced cables 104.; an internal liner 106, (for example, although not limited to high temperature conductive tape); a plurality of steel reinforced cables 108; internal material 110 (for example Tefzel ™ material) containing copper conductors 112; 118 stainless steel tubes surrounding by a copper conductor 113 and optical fibers 120 with FBG spaced along their length; and an internal insulating material 122 containing steel reinforced cables 125 and an optical fiber 126 with a plurality of FBG spaced apart along its length. To allow precise correlation between the temperature of two fibers 120 and 126, the drill string 100 is constructed in one aspect so that the FBG 127 of the fiber 126 and the FBG 129 in the outer fiber 120 occur substantially in the same position axial drilling cable (see for example Figure 3D). The spaces 130 can be filled with cotton strips with paste insulation around them. The surface system of Figure 3A can be used for the central fiber. An additional surface system for the external tapes 120 is the same, although only the Fabry-Perot filter system is used. The location angle of the outer conductor is sufficiently large and the inner diameter of the stainless steel tube is sufficiently large so that the fibers 120 remain loose inside the tubes, i.e. the fibers experience little or no tension. For example, when the location angle of the external conductor is 20 °, the internal diameter of the stainless steel tube is 0.058 cm (0.023 inches), the outer diameter of the fiber is 0.0074 centimeters (0.00295 inches), the center of the stainless steel pipe is at least one radius (distance) of 0.2527 centimeters (0.0995 inches) from the center of the wire of perforation 100, drill string 100 is preferred to be stretched to 0.95% without tensioning the fibers 120 (assuming that fibers 12Q effectively reside in the center of the steel pipe when the stainless steel pipe is under tension-free conditions at room temperature) . In this loose condition, the readings from the FBGs on the fibers 120 are used to measure only the temperature. These temperature readings are then used together with the readings from the FBG of the central fiber to obtain the voltage located in the drill string, calculated by known methods (for example as in "Fiber optic Bragg grating sensors", Morey et al. al, SPIE Vol. 1169, Fiber Optic Laser Sensor VII, 1989, pp 98-107; and "3M Fiber Bragg Gratings Application Note," February 1996). This method gives the localized tension of the drill string and the temperatures experienced by the drill cables. Such measurements have not been possible with cables with magnetic markers. Figure 5 shows a prior art central fiber component 150 similar to the core member housing fiber 126 of Figure 4 but with a jacket of Kynar ™ 152 material surrounding the glass / epoxy 154 which in turn encircles a jacket internal 156. The jacket 156 comprises 3 optical fibers 160 and each with a plurality of separate FBGs. The fibers 160 are placed in an amount of a diverter, for example, silicon RTV 164. When the jacket 152 is made of a rigid material, for example, rigid Kynar ™ material, a central fiber is thus protected from the pressure of the well drilling. Example: Measurement of Voltage and Temperature The effects of temperature and tension on the displacement of the Bragg wavelength are modeled in 3M Fiber Bragg Gratings Application Note (cited above) in an equation on page 2 of the same. A 3M fiber has the following typical values: ?? 6 b = 0.79e + 6.3 10"? T? where? T is in ° C. These values could also be determined experimentally from an arbitrary fiber with an FBG. Assuming that a first FBG on the outside (similar to fiber 120, Figure 4) measures a ?? b = 1.22 nm at? B = 1552 nm (? B is measured at the surface temperature of 25 ° C). Since e = 0, for this external fiber _? _ = 6.3 x 10"? T?" 1.22 1? T = 125 '1552 6.3x10" For a second FBG in the center (for example a fiber 126, Figure 4) in the same position as before the FBG described above, measures a β b = 4.9 nm, 4. 9 1. 22 = 0 7 9e + 3"6 8 - 0. 7 9ß that is e = 0. 003 = 0. 3% 1552 The above measurement therefore indicates, at the location of the FBGs, a well drilling temperature of 25 ° C + 125 ° C = 150 ° C, and a drilling cable tension of 0.3%. Perforation Cable Length Measurement An acoustic transmitter A (see Figure 3A) is placed on the surface of the earth E on the borehole L. As the drill wire W travels through this transmitter, the acoustic signal from the acoustic transmitter A is detected when passing the FBG. Using the Doppler effect, the exact moment when the FBGs travel through the transmitter is calculated. When the FBGs are below the transmitter, but moving away from the transmitter, the detected acoustic frequency is slightly higher than that transmitted. When the FBGs are below the transmitter, although moving away from the transmitter, the detected acoustic frequency is slightly lower than that transmitted. In an aspect to improve the transfer of efficient acoustic energy from the energy transferred from the acoustic transmitter to the FBG, a medium between the acoustic transmitter A and the drill string W is replaced with a solid, with a hole over the well bore through which the drill rope slides as it descends into the wellbore L. A FBG is able to measure the pressure changes in the well drilling in terms of the acceleration emitted from the acoustic transmitter A. This change in pressure is transmitted to the dynamic change in the deviation of the light of the Fabry-Perot wavelength in the returns reflected from a FBG. Although the measurement scheme that uses the above described, also gives a dynamic change in the wavelength, the scheme described below is suitable for measuring the dynamic displacement in the wavelength. This measurement scheme uses the asymmetric interferometer 206 which translates the dynamic displacement into the wavelength within the phase changes which, in turn, results in an acoustic signal that identifies the specific FBG that enters or leaves the borehole. Well L. A time gate signal from computer 210 is also used to restrict the measurement to a FBG at a time. A prior known position of the drill string together with the direction of its movement allows the computer 210 which is known to be the next FBG to enter the well bore L thus allowing a time gate signal to be calculated. Alternatively, the computer selects a search mode while the measurement is made on a subset of similar FBGs entering or leaving the wellbore. The FBG subset contains one of all the FBGs in the drill string W. In some aspects, the search mode is used only occasionally since it takes relatively longer to acquire more than one measurement. In a modality in which a central fiber is not housed in a loose tube, its FBG collects the acoustic energy and is used in the measurement scheme. Again, this measurement involves sending an impulse from a broadband source B within the central fiber. After identifying the particular FBG that has passed through the acoustic wave field, the time of travel from the FBG is calculated, for example by a high-speed clock not shown on the computer 210. This travel time together with an awareness The total length of the drill string gives the length of the drill string inside the borehole after the appropriate temperature correction. This displacement time is measured by another measurement scheme. In this scheme, the pulses are transmitted from the broadband source B. The pulse width is narrow enough to distinguish the reflected returns from the adjacent FBGs. For example, with a separation of 25 meters between the adjacent FBGs, the maximum pulse width is (25) (2) (n) / c = 250 ns, where n is the refractive index and is equal to 1.5 (for the illustration) and c is the speed of light in free space. In practice, an impulse whose width is much less than the maximum value of 250 nanoseconds is transmitted. To measure the total length of the drill wire W, a FBG is placed at the end of the drill string or inside the torpedo / cable head. The travel time for this last FBG gives the total length of the drill string. Alternatively, the prior art known method OTDR ("Optical Time Domain Reflectometer") for measuring reflection from abrupt termination (eg breakage in a fiber) in the torpedo / cable head, is used to obtain the length Total drilling cable. Example: Measurement of the Drill Cable Length A time t2 is the time of displacement in two directions from the surface of a fiber (for example fiber 126 Figure 4) to the end of the drilling hole of the fiber. Let time be the displacement time in both directions from the fiber surface end to an FBG that is traveling through an acoustic signal generator (as in the system of Figure 3A). Suppose that t2 is measured to be 32.08 μs and ti is measured to be 2.90 μs. Thus, the total two-way displacement time that pertains to the portion of the drill string that is extended within the bore hole is t2-t? = 29.18 μs. Letting L be this length of the drill string, which is deployed inside the well bore. Leaving L0 which is the total length of the drill string (which includes the surface portion). Because temperature affects the refractive index, this effect of temperature is corrected when calculating the length of the drill string using the time of travel in two directions, measured. Leaving T2 = 150 ° C which is the temperature measured by the FBG at the orifice end, and T? = 25 ° C which is the surface temperature. The refractive index at the orifice end is O2 = no [1 + H * (r2-rin where no = 1.45 which is the refractive index in T = 25 ° C on the surface. dn for the fiber is 1.0 x 10 ~ 5 ° C-1 dT Therefore, n (L0) = 1.45 * [1 + 1.0 xlO'5 * (150 -25)] = 1.4518 For the simplicity of the illustration, it is also assumed that the geothermal temperature gradient varies linearly with depth, and that the wellbore is vertical. Then, it can be shown that 2n L where c = 2.9979 x 108 m / s is the speed of light in the free space, and na is the average refractive index of the fiber within the wellbore. This average is n .J ^ 1.45 * 1.4518 0 2 2 Therefore from the equation for t2-t ?, _, 2 * 1.4509 * L 29.18 x 10 ~ 6 = - 2.9979 108 L = 3014.6 meters Therefore, the end of the drill string is at a depth of 3014.6 meters measured from the acoustic surface generator position.

The total length of the drill string, in this state, under the load is + 2.90xlO-6 * C = 3014 > 5 + 299_8 2 * n0 = 3314.4 meters. The geothermal temperature gradient contributes to a difference of 0.0625% in L. This difference is equivalent to a length of 1.9 meters. In the conclusion, therefore, it is noted that the present invention and the embodiments described herein and those covered by the appended claims are well adapted to carry out the objectives and obtain the stated purposes. Certain changes can be made in the subject matter without departing from the spirit and scope of this invention. It is noted that changes are possible within the scope of this invention and that it is further intended that each element or step cited in any of the following claims be understood as referring to all equivalent elements or steps. - The following claims are intended to cover the invention as widely as legally possible in any form that may be used.

Claims (25)

1. CLAIMS 1. A cable for well drilling logging operations, characterized in that the cable comprises well drilling cable apparatus having separate ends including a first end and a second end, at least one optical fiber within the apparatus of well drilling cable and extending therein from the first end of the well drilling cable apparatus to the second end thereof, and at least one fiber Bragg grid in at least one optical fiber. The cable according to claim 1, characterized in that at least one optical fiber is a plurality of optical fibers. The cable according to claim 1, characterized in that at least one fiber Bragg grating is a plurality of fiber Bragg gratings. The cable according to claim 1, characterized in that the wellbore recording operations include the cable tension measurement operations, the cable length measurement, and the temperature measurement operations. The cable according to claim 1, characterized in that the well drilling cable apparatus includes a plurality of cables armed around at least one optical fiber. The cable according to claim 1, characterized in that at least one optical fiber is at least two optical fibers separated each with a plurality of fiber Bragg gratings. The cable according to claim 6, characterized in that it further comprises a hollow metal tube extending from the first end to the second end of the well drilling cable apparatus, at least two separate optical fibers including at least less a first optical fiber and a second optical fiber, the first optical fiber that resides loosely inside the hollow metal tube. The cable according to claim 7, characterized in that it further comprises the second optical fiber placed in the well drilling cable apparatus so that the second optical fiber is extended as the well-hole cable apparatus extends. The cable according to claim 7, characterized in that the hollow metal tube is made of stainless steel and the cable further comprises. a plurality of copper strands around the hollow metal tube, said strands extend from the first end to the second end of the well drilling cable apparatus. 10. The cable in accordance with the claim 9, characterized in that it also comprises insulating material between the first optical fiber and the second optical fiber. The cable according to claim 1, characterized in that it further comprises at least one conductor cable in the well drilling cable apparatus and extending from the first end to the second end thereof. 12. A cable for well drilling logging operations including cable tension measurement operations, cable length measurement and temperature measurement operations, the wire is characterized in that it comprises the well drilling cable apparatus that has separate ends including a first end and a second end, a plurality of optical fibers within the well drilling cable apparatus and extending therefrom from the first end of the well drilling cable apparatus to the second end of the well drilling cable apparatus. same, a plurality of cables armed around each optical fiber, and a plurality of Bragg fiber grids in each of the plurality of optical fibers, a hollow stainless steel tube extending from the first end to the second end of the apparatus of well drilling cable, the plurality of optical fibers including at least a first optical fiber and a second unda fiber optic, the first fiber optic that resides free of tension inside the hollow metal tube, a plurality of copper strands around the hollow stainless steel tube, said strands extending from the first end to the second end of the cable apparatus of the well bore, and insulating material between the optical fibers. 13. A cable for well drilling logging operations, the wire is characterized in that it comprises a well drilling cable apparatus having separate ends including a first end and a second end, a hollow metal tube extending from the well. first end to the second end of the well drilling cable apparatus, and at least one optical fiber loosely placed inside the hollow metal tube and extending therefrom from the first end of the well drilling cable apparatus to the second end of it. 14. The cable in accordance with the claim 13, characterized in that it also comprises at least one fiber Bragg grating in at least one optical fiber. The cable according to claim 13, characterized in that at least one fiber Bragg grating is a plurality of fiber Bragg gratings, at least one optical fiber outside the hollow metal tube and extending from the first end to the second end of the well drilling cable apparatus, the hollow metal tube made of stainless steel, and the insulating material between adjacent optical fibers. 16. The cable in accordance with the claim 13, characterized in that the hollow metal tube is made of stainless steel with a plurality of copper strands around it extending from the first end to the second end of the well drilling cable apparatus. 17. A system for well drilling cable operations, the system is characterized in that it comprises a control apparatus for controlling the system, a drilling cable having an upper end and a lower end, the drilling cable interconnected with the control apparatus and comprising the well drilling cable apparatus having separate ends including a first end and a second end, at least one optical fiber within the well drilling cable apparatus and extending therefrom from the first end of the well drilling cable apparatus to the second end thereof, and at least one fiber Bragg grid in at least one optical fiber, an optical coupler interconnected with the control apparatus and with at least one optical fiber , a source interconnected with the control apparatus to send a light signal through at least one optical fiber, and a detector interconnects with the control apparatus and for detecting a signal reflected from at least one fiber Bragg grid. The system according to claim 17, characterized in that it also comprises an insulator to prevent reflected light from entering the source. 19. The system according to claim 17, characterized in that at least one optical fiber is a plurality of optical fibers and at least one fiber Bragg grid is a plurality of fiber Bragg gratings. 20. The system in accordance with the claim 17, characterized in that it further comprises an acoustic transmitter _ interconnected with the control apparatus and placed adjacent to the drilling cable and passing which, the drilling cable is movable, the acoustic transmitter interconnected with the control apparatus and for transmitting an acoustic signal towards at least one fiber Bragg grid. 21. A method for obtaining data from within a well bore, the method is characterized in that it comprises running a cable inside a well bore extending into the earth from an earth surface, the wire comprising the borehole apparatus. Well drilling cable having separate ends including a first end and a second end, at least one optical fiber within the well drilling cable apparatus and extending therefrom from the first end of the cable drilling apparatus perforating the well to the second end thereof and at least one fiber Bragg grid in at least one optical fiber, sending a signal with the signal transmission means towards at least one fiber Bragg grid, receiving the signal with signal receiving means, and process the signal to obtain the data. 22. The method of compliance with the claim 21, wherein the data includes data related to the cable length from the ground surface to at least one fiber Bragg grid, wherein at least one fiber Bragg grid is at least two Bragg fiber grids including a first fiber Bragg grid and a second fiber Bragg grid below and spaced a distance d from the first fiber Bragg grid and where an acoustic transmitter is placed adjacent to the cable so that the acoustic signal is transmissible to and sensitive by a grid Bragg fiber that passes to the acoustic transmitter, each fiber grid has a wavelength of Identification fiber bragg, the method characterized in that it further comprises sending an acoustic signal to the first fiber Bragg grid at a known location with respect to the acoustic transmitter and sending the fiber Bragg wavelength therefrom and thereby identifying the first fiber Bragg grid, and calculate the distance from the acoustic transmitter to the second fiber Bragg grid based on the distance d and the known location of the first fiber Bragg grid. The method according to claim 21, wherein at least one fiber Bragg grid is a plurality of separate fiber Bragg gratings and wherein a final fiber Bragg grid in at least one optical fiber is placed in the lower end thereof in the well drilling cable apparatus, and the method is characterized in that it further comprises. send a signal from a broadband source in at least one optical fiber to the grid Final fiber Bragg, and with a sensor at a known distance from the final fiber Bragg grid, detect a return signal from the fiber Bragg grid to the sensor and a time of travel of the return signal from the grid Final fiber bragg to the sensor, calculate the length of the drilling cable apparatus from the sensor to the final fiber Bragg grid. 24. The method according to claim 20, wherein at least one fiber Bragg grid has a Bragg wavelength of identification fiber, the method is characterized in that it further comprises sending an interrogation signal from a signal transmitter to below, towards at least one fiber Bragg grid, receiving with the receiving apparatus a signal reflected from at least one fiber Bragg grid, and calculating a difference between the wavelength of the reflected signal and the Bragg wavelength of fiber to determine a deviation from the wavelength Bragg of fiber indicative of the tension on at least one Bragg grid of fiber. 25. The method according to claim 21, wherein at least one fiber Bragg grating has a single wavelength, the method is characterized in that it includes displacing the fiber Bragg cable and grid to a known location below in the Well drilling, at the known location, measure the wavelength of the fiber Bragg grid, calculate a change in wavelength between the single wavelength of fiber Bragg grid and the measured wavelength at the known location down in the wellbore, and use the calculated change in wavelength, determining the temperature at the known location below in the wellbore.