CA2244829C - Well cable monitor system - Google Patents

Abstract

The present invention, in certain aspects, discloses a wellbore cable with one or more fiber optic fibers having one or more fiber Bragg gratings thereon or therein. Such a cable is used in a system according to the present invention with an appropriate broadband source, detector system and other items (e. g. but not limited to isolators, couplers, computers, and acoustic transmitters) to measure: the length of a cable in a wellbore, localized temperature in a wellbore, and strain on a cable or other item in a wellbore. Methods have been invented for using such a wellbore cable for such uses. The present invention discloses a wellbore logging cable or wireline with a hollow metal tube through which extends strain-free at least one fiber optic; in one aspect the at least one fiber optic is one, two, three, four or more fiber optics and each has at least one, two, three, four, five or more fiber Bragg gratings; and in another aspect such a cable or wireline has one, two, three, four or more fiber optic outside the hollow metal tube.

Description

WELL CABLE MONITOR SYSTEM
BACKGROUND OF THE INVENTION
Field Of The Invention The present invention is directed to the field of armored cables used in the electrical logging of oil and gas wells and to the monitoring of the length of such cables, detecting temperature, and strains imposed on the cables. In one particular aspect, the present invention is directed to a monitoring system with one or more fiber optics with one or more fiber Bragg gratings.
Description of Related Art Electric wireline logging cables convey measuring instruments into earth wellbores that generate signals related to physical properties of the earth formations and make it possible to record the properties of the earth formations at a plurality of depths within the wellbore. This is usually done while pulling the instrument out of the wellbore by reeling the logging cable onto a winch or similar spooling device while recording signals generated by the instruments and, thus, a record of the measurements is made.
In certain prior art systems, measurement of the depth of an instrument in a wellbore is done by using a calibrated wheel placed in frictional contact with a cable. The calibrated wheel turns correspondingly with the amount of linear motion of the cable past the wheel as the cable is moved into or out of the wellbore by the winch. In one aspect a plurality of magnetic markers are spaced apart on a cable.
The wheel can be rotationally coupled to a mechanical counter

- 2 calibrated to indicate the length of cable moved past the wheel, or the wheel can be coupled to an encoder connected to a counter or computer for electronically indicating the length of cable moving past the wheel. Such wheels can accurately determine the total length of cable which has been moved past the wheel into the wellbore, but the true depth of the instrument in the wellbore may not correspond exactly to the total length of cable moving past the wheel because the cable is subject to stretch as tension on the cable varies.
Both temperature and weight affect the tension on cables.
The total weight of a cable disposed within a wellbore can be as much as 500 pounds for each 1000 feet of.cable, and the instrument itself has a significant weight when it is inserted into the wellbore, which can vary depending on how much of the instrument volume is enclosed air space and on the density of a fluid in the wellbore. The measurements made by the instrument can have been made at depths as much as twenty feet or more different from the depth indicated by the calibrated wheel because of tension induced stretch in the cable as the instrument is pulled out of the wellbore.
The least predictable parameter that affects cable tension is friction, which can increase the stretch on the cable as it is moved into and out of the wellbore because the wall surface of the wellbore has an .unknown degree of roughness and the earth formations penetrated by the wellbore have unknown frictional coefficients. Drilling mud or fluid in the wellbore can have varying viscosity at different depths within a particular wellbore, making a determination of friction effects even more difficult.
U.S. Patent No. 4,803,479 to Graebner et al discloses a depth measurement method for compensating for the amount of stretch in the cable which includes making a measurement of a shift in the phase of an electrical signal sent through the entire cable and returned to equipment at the earth's surface,

- 3 the phase shift measurement related to the phase shift of the same electrical signal sent through a reference cable disposed at the earth's surface having invariable length. In the method of the Graebner patent, phase shift in a constant frequency electrical signal depends only on the change in transmission time of the signal, so phase shift corresponds to a change in the length of the electrical conductors in the cable. A limitation of the method of the Graebner et al '479 patent 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.
Electrical logging cable typically comprises a plurality of insulated electrical conductors covered by helically-wound steel armor wires. A logging cable typically comprises seven conductors, six of the conductors being helically wound around the seventh conductor. When such a multiple conductor cable is stretched, some of the stretch is consumed by unwinding the helically wound conductors, so the cable length increases more than the length of the helically-wound conductors increases.
Another limitation of the method disclosed in the Graebner et al '479 patent is that the ratio of change in cable length to the phase shift of the electrical signal, called the scale factor, must be determined for each particular cable because electrical signal transmission properties can vary somewhat among different cables. A still further limitation of the method disclosed in the Graebner et al '479 patent is the need to use an additional conductive means at the earth's surface to provide a fixed length phase reference for comparison of phase change in the logging cable. A substantial length of cable to be used as a fixed length reference can occupy a significant storage space, which can be impractical.
Often small lengths of cable are cut such as 100 to 300 feet from the end of a particular cable which is lowered into the wellbore as that end of the cable becomes worn or damaged.

- 4 In other circumstances, the cable is cut in order to retrieve an instrument which has become stuck in the wellbore, the cut cable later reassembled by splicing. When a cable is cut, the scale factor may have to be again determined by imparting a known amount of stretch to the cable and measuring the phase shift caused by the known stretch. It is difficult to recalibrate the scale factor at the wellbore location since equipment intended to impart a known stretch to the cable typically can be located only at a specialized facility.
The system of U.S. Patent 4,803,479 is also deficient in that the accuracy of the measurement of phase shift declines rapidly with increasing frequency of change in length of the cable. Higher frequency changes in the amount of cable stretch can be caused by "stick-slip" motion of the logging tool, as the combination of gravity and friction of the wellbore momentarily overcomes the upward pull of the logging cable, only to be violently released in a spring-like motion as the frictional force is overcome when the upward tension on the cable builds sufficiently.
U.S. Patent No. 3,490,149 to Bowers discloses a method of determining the depth of logging tools in a wellbore. The system includes an accelerometer for measuring acceleration of the logging tools coaxial with the wellbore. Acceleration measurements of the logging tools coaxial with the wellbore are doubly integrated to provide a determination of change in axial position of the logging tools. The change in axial position determined from the doubly integrated accelerometer measurements is used to adjust the measured position of the tool as determined by measurements of the amount of cable which has passed a device for measuring the amount of cable extended into the wellbore. A drawback to the system is that the doubly integrated acceleration measurements typically must be band limited by a filter to remove DC and very low frequency AC output from the accelerometer to correct for

- 5 "drift in the zero reference" (also known in the art as bias error). If the acceleration on the tool falls below a cutoff frequency of the filter, then low frequency accelerations on the. tool as may be caused by forces such as friction, which changes the tensile force on, and therefore the length of, the cable, may go undetected. The system, therefore, is useful only to correct depth measurements for higher frequency accelerations on the logging tools.
U.S. Patent No. 4,545,242 to Chan discloses an improvement on the method disclosed in the Bowers '149 patent.
The system includes feedback amplifiers to decrease an error signal generated in the process of integrating accelerometer measurements to determine the true position of the logging tools in the wellbore. This system has the limitation of having substantially no system response below the lower cutoff frequency of a filter applied to the output of the accelerometers. The systems disclosed in Bowers '149 and Chan '242 are unable to provide accurate depth information in the event the electrical cable is "stretched" at frequencies below the cutoff of the filter applied to the accelerometer.
Methods that involve reading magnetic markers have several disadvantages: 1) the sharpness of the magnetic markers diminishes with usage and time, and therefore the positional accuracy of the markers also diminishes; 2) periodically the markers need to be re-magnetized because they lose magnetism with usage and time; 3) wireline length between the magnetic markers, assumed to be fixed, is only approximately fixed and the wireline stretches with use, and therefore the length between the markers increases; and 4) slippage is induced by friction measuring wheels, particularly on wet wirelines and/or wirelines coated with drilling fluid while coming out of a borehole.
Various known armored electrical cables have one or more insulated electrical conductors which are used to supply

6 electrical power to well logging instruments and to transmit signals from the instruments to equipment at the earth's surface for processing the signals. These cables have steel armor wires wound helically around the electrical conductors to provide torsion resistance, tensile strength, and abrasion resistance.
A variety of known prior art well logging cables have optical fibers and use optical telemetry at high frequencies and at data transmission rates higher than those of electrical signal transmission.
Known prior art cables have optical fibers enclosed in a steel tube. Another prior art combination fiber-optic/electrical well logging cable has an optical fiber enclosed in a steel tube in the center of a well logging cable with conductive members positioned externally to a central tube containing the optical fiber and constructed of copper clad steel wire. Another type of prior art combination fiber-optic/electrical well logging cable has a plastic-sheathed optical fiber instead of one or more electrical conductors. One prior art combination fiber-optic/electrical well logging cable includes an optical fiber enclosed in a metal tube surrounded by twisted copper strands to conduct electrical power and electrical signals.
U.S. Patent 5,495,547, co-owned with the present invention, discloses a combination fiber-optical/electrical conductor well logging cable. This patent discusses problems associated with prior art cables discussed above. As shown in Fig. lA, U.S. Patent 5,495,547 discloses, in certain embodiments, a well logging cable including first elements which are a copper-clad steel wire surrounded by copper strands and covered in an electrically insulating material, and at least one second element including at least one optical fiber enclosed in a metal tube, copper strands surrounding the _ 7 tube and covered by the electrically insulating material. The first elements and the at least one second element are arranged in a central bundle. The second element is positioned in the bundle so as to be helically wound around a central axis of the bundle. The bundle is surrounded by armor wires helically wound externally to the bundle. A
cross-section of such a prior art well logging cable 10 is shown in Fig. lA and is described in U.S. Patent 5,495,547.
Parts of the cable 10 are shown in Figs. 1B and 1C. The cable 10 includes seven, plastic-insulated conductor elements positioned in a central bundle 15 having a substantially regular hexagonal pattern, wherein six of the elements surround the seventh element. First elements 16 are, in one aspect, insulated electrical conductor elements. including a copper covered steel wire about 0.027 inches diameter surrounded by nine copper wires each of which is about 0.0128 inches diameter. The first elements 16 include an exterior insulating 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 trade name of E. I. du Pont de Nemours & Co. Second elements 18 each includes, among other things, an optical fiber disposed within a stainless-steel tube. The cable 10 includes two symmetrically positioned second elements 18 which may be positioned at any or all of the six externally positioned locations on the regular hexagonal pattern formed by the seven elements.
Void 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 armor wires, formed into an inner armor sheath. The inner armor sheath 14 is itself externally covered with helically wound galvanized steel armor wires formed into an outer armor sheath. The inner armor sheath 14 and the outer armor sheath 12 are designed to provide significant tensile strength and abrasion resistance to the cable 10. In one aspect the cable is intended to be used in a chemically hostile environment such as a wellbore having significant quantities of hydrogen sulfide, and the armor wires 12, 14 alternatively are composed of a cobalt-nickel alloy such as one identified by industry 10 code MP-35N.
One of the second elements 18 is shown in more detail in Fig. 1B 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 has, in one aspect, an external diameter of 0.033 inches and in internal diameter of 0.023 inches. The tube 24 provides abrasion and bending protection to the optical fiber 22, and excludes fluids in the wellbore from the cable. The tube 24 can be copper plated to reduce its electrical resistance and surrounded by twelve copper wire strands shown generally at 26. The wire strands 26 each can be 0.01 inches in diameter. The combination of the tube 24 and strands 26 provides a conductor having an electrical resistance of less than 10 ohms per 1,000 foot length. The tube 24 and the copper strands 26 are further covered with plastic insulation 20 composed of a heat resistant plastic such as ETFE, or polypropylene. The external diameter of the insulation 20 on the second element 18 is substantially the same as the external diameter of the insulation on the first element 16, so that the hexagonal pattern of the seven elements as shown in the cross-section of Fig. lA is substantially symmetrical, despite the relative position of the second element 18 within the hexagonal pattern of the bundle 15. The second elements 18 can be positioned at any one or all of the six-external positions of the hexagonal structure as shown in Fig. lA. The second element 18, in one aspect can be placed in an external location on the hexagonal structure of the bundle 15 because the elements 16, 18 in the external locations are helically-wound around the element in the central position. For reasons such as lateral reduction in pitch diameter with axial strain, unwinding of the helical lay and the longer overall length of the helically wound external elements relative to the length of the central element 18, the externally positioned elements 16, 18 undergo reduced axial strain relative to the axial elongation of the cable thereby reducing the possibility of axial strain-induced failure of the tube 24 and the fiber 22.
Second elements 18, in one aspect, are positioned at two, external locations opposite to each other in the hexagonal pattern.
Fig. 1C shows a cross-section of a first element 16 in more detail. The first element 16 has, in one aspect, a steel wire 28 clad or plated with metallic copper to have an external diameter of about 0.027 inches, thereby reducing the electrical resistance of the wire 28. The copper-covered wire 28 is further surrounded by nine copper strands, shown generally at 30 and having an external diameter of 0.0128 inches. The combination of the steel wire 28 and the copper strands 30 has an electrical resistance of less than 7 ohms per 1,000 feet of length. The strands 30 are covered with an electrical insulating material 32 such as polypropylene or PTFE. The second elements 18 are designed so that the combination of the tube 24 and wire strands 26 has an external diameter enabling 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 signal transmission properties as do other cables made according to the prior art.

U.S. Patent 5,541,587 co-owned with the present invention discloses a system for determining the depth of a logging tool attached to a cable extended into a wellbore penetrating an earth formation. A particular embodiment of 5 the system includes a circuit for generating a measurement of phase shift in a sinusoidal electrical signal transmitted through the cable, the phase shift in the signal corresponding to the length of the cable. The system also comprises an accelerometer disposed within the tool and 10 electrically connected to a bandpass filter. A double integrator is connected to the bandpass filter. The double integrator calculates position of the tool coaxial with the wellbore. The phase shift measurement is passed through a low-pass filter. The low-pass filter and the bandpass filter comprise at lease some degree of bandpass overlap. The integrator output is used to generate a scale factor which is applied to the filtered phase shift measurement. The scaled phase shift measurement is conducted to a depth computer as arc a signal generated by a depth encoder and the integrated accelerometer measurements. The depth encoder signal corresponds to the amount of cable extended into the wellbore. The depth computer calculates the depth of the tool in the wellbore by summing the scaled phase shift measurements, the integrated accelerometer measurements and the encoder measurements.
Fig. 2A and 2B show a prior art cable disclosed in U.S.
Patent 5,541,587. The cable is a typical multi-conductor well logging cable whose exterior comprises helically wound armor wires made, e.g., of steel. Electrical conductors within the armor wires include a central conductor and outer helically wound conductors. The central conductor is substantially collinear with the length of the cable and is substantially coaxial with the cable throughout its entire length.

There has long been a need for a monitoring system for well logging cable which accurately indicates cable length, strain on a cable, and/or temperature at a location of the cable.
SU1~1ARY OF THE PRESENT INVENTION
The present invention, in certain embodiments, discloses a system for accurately determining the length of a cable or wireline in a wellbore to thereby determine the location of an instrument on the cable in the wellbore and, thus, the location at which the instrument is activated to take a measurement . In one aspect the system includes a cable, a multi-wavelength emitting source at the surface interconnected with the cable, the cable having one or more fiber optics as discussed below with one or more fiber Bragg gratings, and a coupler coupling the fiber optics) to the source.
Several advantages are achieved by using fiber Bragg gratings. The grating is a permanent part of the wireline, i.e. it is not as easily removed as magnetic markers, and,it does not need to be refreshed as do magnetic markers. The distance between two gratings can be determined easily in real-time with suitable instrumentation. The gratings provide dual functions of measuring temperature and strain.
Replacement of magnetic sensing with acoustic sensing and the use of the doppler effect provide much more accurate measurements. Gratings can be applied to or formed in a fiber in a very controlled and accurate environment.
In one aspect of a system according to the present invention a cable's central conductor is a fiber optic with one or more fiber Bragg gratings thereon, formed therein, or some combination thereof.
The one (or more) fiber Bragg gratings has a unique Bragg wavelength with a value, in certain embodiments, sufficiently separated from the others to facilitate detection.
In one embodiment in which such a system is used for a separate strain-free temperature measurement, two fiber optic fibers are used each with a plurality of spaced-apart gratings. One of the fibers is placed loosely inside a metal (e.g. steel or stainless steel) tube e.g. in place of one of the outer conductors of a cable (e.g., but not limited to, a cable as in Fig. lA or Fig. 2A). The other fiber is disposed in place of a cable's central conductor (e. g., but not limited to, a cable as in Fig. 1A or Fig. 2A). In another aspect, the metal tube is stainless steel wrapped with copper strands and is used as a conductor. One or more such conductors may be employed.
Methods according to the present invention using systems as disclosed herein include methods for determining localized temperature in a wellbore, methods for measuring strain on a cable in a wellbore, and methods for determining the length of a cable in a wellbore.
Systems and methods according to the present invention are very useful in a variety of situations. When logging tools and/or other downhole devices are conveyed via drill pipe ("Pipe Conveyed Logging"), or via mechanical downhole propulsion devices like well tractors or crawlers, the present invention's ability to determine localized line stretch aids in the determination and localization of key seating; the determination of effective pulling strength in high angle and/or horizontal sections while tractoring out of the horizontal section or out of the hole; and the determination of effective line feed rate while tractoring into and/or through horizontal sections to prevent key seating and/or "bird nesting". Control of anchor lines is made possible where localized stretch determination aids in the determination of the effective length and holding characteristics of sea bed buried anchor cable/chain combinations; the determination of net pull on the anchor/anchor chain combination; and the precise determination and localization of stretch effects for feedback to a tensioning system. For tension leg and ocean bottom tethered applications, the present invention provides the ability to separate load and stretch effects induced by surface wave motion from, load and stretch effects induced by ocean bottom currents.
It is, therefore, an object of at least certain preferred embodiments of the present invention to provide new, unique, useful, nonobvious, and effective systems with well logging cables having fiber optics with one or more fiber Bragg gratings and cables with such fibers, and such systems useful in methods for determining length of a cable in a wellbore, localized temperature in a wellbore, and strain on a member in a wellbore;
Such cables which have a hollow metal tube with a fiber optic loosely disposed therein, either a fiber optic with one or more fiber Bragg gratings or without any such grating; and Such systems for measuring steady shift and dynamic shift of a Bragg wavelength of a fiber Bragg grating.
Certain embodiments of this invention are not limited to any particular individual feature disclosed here, but include combinations of them distinguished from the prior art in their structures and functions. Features of the invention have been broadly described so that the detailed descriptions that follow may be better understood, and in order that the contributions of this invention to the arts 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 to this invention. Those skilled in the art who have the benefit of this invention, its teachings, and suggestions will appreciate that the conceptions of this disclosure may be used as a creative basis for designing other structures, methods and systems for carrying out and practicing the present invention. The claims of this invention are to be read to include any legally equivalent devices or methods which do not depart from the spirit and scope of the present invention.
The present invention recognizes and addresses the previously-mentioned problems and long-felt needs and provides a solution to those problems and a satisfactory meeting of those needs in its various possible embodiments and equivalents thereof. To one skilled in this art who has the benefits of this invention's realizations, teachings, disclosures, and suggestions, other purposes and advantages will be appreciated from the following description of preferred embodiments, given for the purpose of disclosure, when taken in conjunction with the accompanying drawings. The detail in these descriptions is not intended to thwart this patent's object to claim this invention no matter how others may later disguise it by variations in form or additions of further improvements.
DESCRIPTION OF THE DRAWINGS
A more particular description of embodiments of the invention briefly summarized above may be had by references to the embodiments which are shown in the drawings which form a part of this specification. These drawings illustrate certain preferred embodiments and are not to be used to improperly limit the scope of the invention which may have other equally effective or legally equivalent embodiments.
Fig. 1A is a cross-section view of a prior art well logging cable . Figs . 1B and 1C are cross-section views of parts of the cable of Fig. lA.
Fig. 2A is a cross-section view of a prior art well logging cable. Fig. 2B is a partial side view of the cable . 15 of Fig. 2A.
Fig. 3A is a side schematic view of a system according to the present invention. Fig. 3B is a schematic view of a signal processing method useful with the system of Fig. 3A.
Fig. 3C is a schematic view of a signal processing method useful with the system of Fig. 3A. Fig. 3D is a side schematic view of a fiber optic system according to the present invention.
Fig. 4 is a cross-section view of a well logging cable according to the present invention.
Fig. 5 is a cross-section view of part of a well logging cable according to the present invention.
Fig. 6 is a graphic representation of an output of a filter used in one system and method according to the present invention.
DESCRIPTION OF EMBODIMENTS PREFERRED
AT THE TIME OF FILING FOR THIS PATENT
Fig. 3A illustrates a system S according to the present invention which has a wireline W with a fiber optic fiber 0 with built in fiber Bragg gratings ("FBG's") at specified intervals (e. g. between about 1 and about 20 or more meters apart) encased in a tight silicon/TeflonTM/TefzelTM buffer and with an outer layer of steel armor wires like the "steel-light" cable made by Rochester Co. A single fiber element is, in one aspect, is placed at the center of the wireline (e. g. in place of the center conductor of wirelines, shown in Figs. lA and 2A). The wireline extends from an earth surface E into a cased wellbore L.
Each FBG in the fiber has a unique Bragg wavelength (e. g.
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 FBG's to facilitate detection. The fiber optic fiber is connected to a coupler, e.g. a 2:1 coupler C (e. g. a 50/50 FO 3662 device from Litton Polyscientific Co.). The coupler is interconnected via an isolator I to a broadband source e.g.
but not limited to a light source or a tunable laser B which can emit signals in a relatively large spectrum of wavelengths, e.g., any suitable wavelength and in certain preferred embodiments, but not limited to, between 780 nanometers and 1650 nanometers.
A detector system D in communication with the fiber optic 0, via the coupler C detects: signals reflected from the FBG's; and measures the wavelength deviation from an FBG's Bragg wavelength.
To enable a separate strain-free measurement of temperature at the location of an FBG, a fiber optic (or at least one fiber optic) with FBG's is placed loosely inside a stainless steel tube T replacing another outer conductor in the wireline ( e.g., see Fig. 3D). The stainless steel tube T is wrapped with copper strands D so that it can also be used as a conductor. Several conductors may be similarly replaced.
Fig. 3C shows a system 200 that measures strains 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 various subsystems and which, via line 212, controls an optical switch 202, e.g. a 3 x 1 model SR 1212 from JDS-Fitel Co. Reflected returns from wellbore fiber optics with FBG' s are transmitted through a fiber 250 to the switch 202. For measuring the deviation due to cable stretch in Bragg wavelength of a fiber Bragg grating on a fiber optic, the sub-system including a Fabry-Perot filter 204 is used. This sub-system is particularly suited for dealing with a steady shift in Bragg wavelength. The sub-system with an interferometer 206 measures dynamic shift in Bragg wavelength and is particularly suited for sensing such a shift induced by an acoustic signal, e.g. as transmitted by the acoustic transmitter A in Fig. 3A. The sub-system with a peak detector 254 senses signal time of arrival and is, therefore, particularly suited for measuring cable length, i.e., length from the surface to a particular FBG on the cable. As shown. in Fig. 3B, the peak detector 254 may be positioned between the Fabry-Perot filter and the mixer. Via a line 214 the computer 210 controls a waveform generator 216 that produces a ramp signal, for mixing with a signal from a Fabry-Perot filter 204 with a mixer 218 and for transmission to the Fabry-Perot filter 204 after summing with a dither signal by a summing device 224. A high frequency dither 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 summing the dither signal with the scanning wave form's ramp signal, the detection of the change in wavelength of the FBG's is facilitated. A mixed electrical signal from the mixer 218 is~transmitted to a low pass filter 234 which differentiates the signal and sends a derivative signal in a line 236 to a zero crossing detector 240 that processes the differentiated signal from the filter 234. The zero crossing detector defines the signal's 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 an FBG and indicative of, e.g., stretch (load) on a wellbore cable, is sent to the computer 210 in the line 242. A mixer 218 multiplies the signal.
With the switch 202 in the appropriate position, reflected returns from the wellbore FBG's are fed in the fiber 222 to a receiver 252 (like the receiver 230) which changes the signal from optical to electrical and then sends an electrical signal to a peak detector 254 in a line 256. The peak detector 254 decides if sufficient light energy is reflected back. If so, the peak detector 254 sends a signal to the computer 210 indicating a reflection.is present. The computer uses the signal to calculate the time of arrival;
e.g. a time t for a signal to go to an FBG and then come back to a sensor, i.e., covering a known one-way distance d where d = t/2c, and t is the two-way travel time.
The fiber 223 conducts reflected light returns from the wellbore FBG's, when the switch 202 is in the appropriate position, to an interferometer 206 via an optical coupler 260.
The interferometer transfers input light in the filter 223 to outgoing light in 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 itself is connected to a phase detector 266 which transforms the phase of the outgoing light signal to an electrical signal indicative of the input light wavelength.
This signal is then sent to the computer 210 in line 268 and the computer 210 computes the dynamic shift in wavelength.
A time gate signal from the computer 210 is transmitted in a line 270 to the phase detector 266. The time gate signal commands the phase detector 266 to work on signals from a selected set of FBG's. This limits the number of FBG's so that sufficient time is available for calculation and detection.
Three different ways of measurement are, therefore, multiplexed in time by the fiber optic switch 202 (e.g. a Dicon Co. optical switch) that switches between optical fibers 221, 222, and 223. Alternatively, the switch may be eliminated and all three fibers connected to the fiber 250 simultaneously. The first measurement scheme uses the tunable fiber Fabry-Perot 204 filter and is suitable for measuring the . 19 strains and temperature in each FBG in a fiber optic 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 wavelength, as described below. The third measurement scheme, described in detail below, uses time of travel information to measure the length from the beginning of the wireline at the surface to each FBG. Thus the total length of wireline deployed into the wellbore can be calculated by combining these measurements.
Localized Temperature & Strain Measurement A method for localized temperature and strain measurement according to the present invention uses the generated data related to the deviation from the Bragg wavelength for each of the various FBG's and gives both static and dynamic stresses imposed upon each FBG. The measurands include strain and temperature. The surface detector system (Figs. 3A and 3B) uses reflected FBG's returns transmitted via line 250 and the Fabry-Perot filter 202. The output of the filter 202 is differentiated by the low pass filter 234 to give a waveform as shown in Fig. 6. This differentiated signal is fed into the zero crossing detector 246, which obtains the deviation from the individual Bragg wavelength for each FBG which indicates strain on a particular fiber Bragg grating.
Expansion of this system using time division multiplexing to be used for larger numbers of FBG's is also within the scope of this invention.
Since temperature and strain affect an FBG in about the same way, to distinguish between these two measurands a further measurement is needed. An additional fiber with built in FBG's helically wound and encased loosely (e. g. strain-free, stretch-free and isolated from strain on the cable) in a stainless steel tube (see Fig. 3D) replaces one of a cable's outer conductors (e.g. see outer conductors in the cables of Figs. lA, 2A and 4).
As shown in Fig. 4, a wireline 100 has a plurality of 5 steel armor wires 104; an inner sheath 106 (e.g. but not limited to high temperature conductive tape); a plurality of steel armor wires 108; inner material 110 (e.g. Tefzel TM
material) containing copper conductors 112; stainless steel tubes 118 surrounded by copper conductor 113 and fiber optic 10 fibers 120 with FBG's spaced apart along its length; and an inner insulation material 122 containing steel armor wires 125 and a fiber optic fiber 126 with a plurality of spaced-apart FBG's along its length. To enable accurate correlation between the temperature of two fibers 120 and 126, the 15 wireline 100 is constructed, in one aspect, such that FBG's 127 of the center fiber 126 and FBG's 129 in the outer fiber 120 occur at substantially the same wireline axial position (see, e.g. Fig. 3D). Spaces 130 may be filled with cotton ribbons with paste insulation therearound.
20 The surface system of Fig. 3A may be used for the center fiber. An additional surface system for the outer fibers 120 is the same, but only the Fabry-Perot filter system is used.
The lay angle of the outer conductor is large enough and the inner diameter of the stainless steel tube is large enough so that the fibers 120 remain loose inside the tubes, i.e. the fibers experience little or no strain. For example, when the lay angle of the outer conductor is 20°, inner diameter of the stainless steel tubing is 0.023", outer diameter of the fiber is 0.00295", the center of the stainless steel tubing is at a radius (distance) of 0.0995" from the center of the wireline 100, the wireline 100 is preferably allowed to stretch up to 0:95% without straining the fibers 120 (assuming that the fibers 120 effectively resides at the center of the steel tubing when the stainless steel tubing is under stress free condition at room temperature). In the loose condition, readings from the FBG's on the fibers 120 are used to measure temperature alone. These temperature readings are then used in conjunction with readings from FBG's on the center fiber to obtain localized strain in the wireline, calculated by known methods (e. g. as in "Fiber optic Bragg grating sensors,"
Morey et al, SPIE Vol. 1169, Fiber Optic Laser Sensors VII, 1989, pp. 98-107; and "3M Fiber Bragg Gratings Application Note," February 1996). This method gives the localized strain on the wireline cable and the temperature experienced by the wireline. Such measurements have not been possible with cables with magnetic markers.
Fig. 5 shows a prior art central fiber component 150 similar to the central element housing fiber 126 of Fig. 4, but with an outer KynarT" material jacket 152 surrounding glass/epoxy 154 which itself surrounds an inner jacket 156.
The inner jacket 156 encompasses three fiber optic fibers 160 each with a plurality of spaced apart FBG's. The fibers 160 are disposed in an amount of a baffle e.g. silicon RTV 164.
When the jacket 152 is made of a rigid material, e.g. rigid Kynar''M material, a center fiber is shielded thereby from borehole pressure.
Example: Strain and Temperature Measurement The effects of temperature and strain on the Bragg wavelength shift is modeled in the 3M Fiber Bragg Gratings Application Note (cited above) in an equation at page 2 thereof.
A 3M fiber has the following typical values:
~~b =0.79e+6.3x10-6~T
~'b where DT is in °C. These values could also be experimentally determined for an arbitrary fiber with an FBG.
Suppose a first FBG in outer (like the fiber 120, Fig.
4 ) measures a A2~6 = 1 . 22 nm at ?~b = 1552 nm (1~b is measured at surface temperature of 25°C) . Since E - 0, for this outer fiber oab = 6.3 x 10- OT
~b ~T = 1.22 * 1 = 125°
1552 6.3 x 10-6 For a second FBG in the center (e. g. a fiber 126, Fig.
4) at the same position as the above described FBG, measures a A?~b = 4.9 nm, 4.9 = 0.79 + 1.22 ~'b ~'b 3 . 68 = 0 . 79E i. e. a = 0. 003 = 0 . 3 0 The above measurement therefore indicates, at the location of the FBG, a borehole temperature of 25°C + 125°C = 150°C, and a wireline strain of 0.30.
Wireline Length Measurement An acoustic transmitter A (see Fig. 3A) is positioned at the earth's surface E above the wellbore L. As the wireline W travels across this transmitter, the acoustic signal from the acoustic transmitter A is sensed by a passing FBG. Using the doppler effect, the exact moment when the FBG travels across the transmitter is calculated. When the FBG is above the transmitter, but moving towards the transmitter, the acoustic frequency detected is slightly higher than that transmitted. When the FBG is below the transmitter, but moving away from the transmitter, the acoustic frequency detected is slightly lower than that transmitted. In one aspect, to enhance efficient acoustic energy transfer from the acoustic transmitter to the FBG, a medium between the acoustic transmitter A and the wireline W is replaced with a solid with a hole above the wellbore through which the wireline slides as it descends in the wellbore L.
An FBG is able to measure pressure changes in the wellbore in terms of acceleration emitted from the acoustic transmitter A. This change in pressure translates to a dynamic change in deviation of light Fabry-Perot wavelength in the reflected returns from an FBG.
Although the measurement scheme using the described above also gives a dynamic change in wavelength, the scheme described below is suitable for measuring the dynamic shift in wavelength. This measurement scheme uses the asymmetric interferometer 206 which translates dynamic shift in wavelength into phase changes which, in turn, translate to an acoustic signal which identifies the specific FBG entering or leaving the wellbore L. A time gate signal from the computer 210 is further used to restrict the measurement to one FBG at a time. A previous known position of the wireline together with the direction of its movement enable the computer 210 to know which is the next FBG entering the wellbore L thus enabling the time gate signal to be computed. Alternatively, the computer selects a search mode whereby measurement is made on a subset of likely FBG's entering or leaving the wellbore.
The subset of FBG's contains one to all of the FBG's in the wireline W. In certain aspects, the search mode is used only occasionally since it takes relatively more time to acquire more than one measurement. In an embodiment in which a center fiber is not housed in a loose tube, its FBG's pick up acoustic energy more and is used in this measurement scheme.
Again, this measurement also involves sending a pulse from a broadband source B into the center fiber. After identifying the particular FBG that has passed across the acoustic wavefield, the time of travel from the FBG is then calculated, e.g. by a high speed clock, not shown, the computer 210. This time of travel together with a knowledge of the total length of the wireline gives the length of the wireline inside the wellbore after appropriate temperature correction. This time of travel is measured by another measurement scheme. In this scheme, pulses are transmitted from the broadband source B.
The pulse width is sufficiently narrow to distinguish the reflected returns from adjacent FBG's. For example, with a 25 meter spacing between adjacent FBG's, the maximum pulse width is (25)(2)(n)/c - 250 ns, where n is the index of refraction and equals 1.5 (for illustration) and c is the velocity of light in free space. In practice, a pulse whose width is much smaller than the maximum value of 250 nanoseconds is transmitted.
To measure the total length of the wireline W, a FBG is placed at the end of the wireline or within a torpedo/cable head. The time of travel to this last FBG gives the total length of the wireline. Alternatively, the known prior art OTDR ("Optical Time Domain Reflectometer") method of measuring the reflection from abrupt termination (e. g. break in a fiber) at the torpedo/cable head is used to obtain the total length of the wireline.
Example: Wireline Length Measurement A time t2 is the two-way travel time from the surface end of a fiber (e.g. a fiber 126, Fig. 4) to the borehole end of the fiber. Let time tl be the two-way travel time from the surface end of the fiber to an FBG that is just traveling across an acoustic signal generator (as in the system of Fig.
3A) . Suppose tz is measured to be 32.08 ,us and tl is measured to be 2.90 ,us. Therefore, the total two-way travel time pertaining to the portion . of the wireline that is deployed . 25 into the wellbore is t2 - tl = 29.18 ,us. Let L be this length of the wireline that is deployed into the wellbore. Let Lo be the total length of the wireline (which includes the surface portion).
Because temperature affects the index of refraction, this temperature effect is corrected in calculating wireline length using the measured two-way travel time. Let TZ = 150°C be the temperature measured by the FBG at the borehole end, and T1 =
25°C be the surface temperature. The index of refraction at the borehole end is n2 n° [ 1 + dT * ( TZ T1 ) ]
where no = 1.45 is the index of refraction at T1 = 25°C at the surface. do for the fiber is 1.0 x 10-5 °C-1.
dT
Therefore, n(L°) =1.45* [1+l.OxlO-5* (150-25) ] =1.4518 For simplicity of illustration, it is further assumed that the geothermal temperature gradient varies linearly with depth, and that the wellbore is vertical. Then, it can be shown that 2n L
tz - tl - a c where c = 2.9979 x 108 m/s is the velocity of light in free space, and na is the average index of refraction of the fiber within the wellbore. This average is n - n°+n2 - 1 . 45+1 . 4518 =1 . 450 Therefore from the equation for t2 - tl, 29. 18 x 10-6 = 2 * 1 . 4509 * L
2.9979 x 108 L = 3014.6 meters Therefore, the end of the wireline is at a depth of 3014.6 meters measured from the surface acoustic generator position.
The total length of the wireline, at this state, under load, is 2. 90 x 10- * C
Lo = L + 2 * n - 3014 . 6 + 299. 8 - 3314.4 meters.
The geothermal temperature gradient contributes to a difference of 0.06250 in L. This difference is equivalent to a length of 1.9 m.
In conclusion, therefore, it is seen that the present invention and the embodiments disclosed herein and those covered by the appended claims are well adapted to carry out the objectives and obtain the ends set forth. Certain changes can be made in the subject matter without departing from the spirit and the scope of this invention. It is realized that changes are possible within the scope of this invention and it is further intended that each element or step recited in any of the following claims is to be understood as referring to all equivalent elements or steps. The following claims are intended to cover the invention as broadly as legally possible in whatever form it may be utilized.
What is claimed is:

Claims (25)

CLAIMS:

1. A cable for wellbore logging operations, the cable comprising wellbore cable apparatus having spaced apart ends including a first end and a second end, at least one fiber optic within the wellbore cable apparatus and extending therein from the first end of the wellbore cable apparatus to the second end thereof, and at least one fiber Bragg grating in the at least one fiber optic.

2. The cable of claim 1 wherein the at least one fiber optic is a plurality of fiber optics.

3. The cable of claim 1 wherein the at least one fiber Bragg grating is a plurality of fiber Bragg gratings.

4. The cable of claim 1 wherein the wellbore logging operations include cable strain measurement operations, cable length measurement, and temperature measurement operations.

5. The cable of claim 1 wherein the wellbore cable apparatus includes a plurality of armor wires around the at least one fiber optic.

6. The cable of claim 1 wherein the at least one fiber optic is at least two spaced-apart fiber optics each with a plurality of fiber Bragg gratings.

7. The cable of claim 6 further comprising a hollow metal tube extending from the first end to the second end of the wellbore cable apparatus, the at least two spaced-apart fiber optics including at least a first fiber optic and a second fiber optic, the first fiber optic residing loosely within the hollow metal tube

8. The cable of claim 7 further comprising the second fiber optic disposed in the wellbore cable apparatus so that the second fiber optic is stretched as the wellbore cable apparatus stretches.

9. The cable of claim 7 wherein the hollow metal tube is stainless steel and the cable further comprising a plurality of copper strands around the hollow metal tube, said strands extending from the first end to the second end of the wellbore cable apparatus.

10. The cable of claim 9 further comprising insulation material between the first fiber optic and the second fiber optic.

11. The cable of claim 1 further comprising at least one conductor wire in the wellbore cable apparatus and extending from the first end to the second end thereof.

12. A cable for wellbore logging operations including cable strain measurement operations, cable length measurement, and temperature measurement operations, the cable comprising wellbore cable apparatus having spaced apart ends including a first end and a second end, a plurality of fiber optics within the wellbore cable apparatus and extending therein from the first end of the wellbore cable apparatus to the second end thereof, a plurality of armor wires around each fiber optic, and a plurality of fiber Bragg gratings in each of the plurality of fiber optics, a hollow stainless steel tube extending from the first end to the second end of the wellbore cable apparatus, the plurality of fiber optics including at least a first fiber optic and a second fiber optic, the first fiber optic residing strain-free within 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 wellbore cable apparatus, and insulation material between adjacent fiber optics.

13. A cable for wellbore logging operations, the cable comprising wellbore cable apparatus having spaced apart ends including a first end and a second end, a hollow metal tube extending from the first end to the second end of the wellbore cable apparatus, and at least one fiber optic loosely disposed within the hollow metal tube and extending therein from the first end of the wellbore cable apparatus to the second end thereof.

14. The cable of claim 13 further comprising at least one fiber Bragg grating in the at least one fiber optic.

15. The cable of claim 13 wherein the at least one fiber Bragg grating is a plurality of fiber Bragg gratings, at least one fiber optic outside the hollow metal tube and extending from the first end to the second end of the wellbore cable apparatus, the hollow metal tube made of stainless steel, and insulation material between adjacent fiber optics.

16. The cable of claim 13 wherein the hollow metal tube is stainless steel with a plurality of copper strands therearound that extend from the first end to the second end of the wellbore cable apparatus.

17. A system for wellbore cable operations, the system comprising a control apparatus for controlling the system, a wireline having a top end and a bottom end, the wireline interconnected with the control apparatus and comprising wellbore cable apparatus having spaced apart ends including a first end and a second end, at least one fiber optic within the wellbore cable apparatus and extending therein from the first end of the wellbore cable apparatus to the second end thereof, and at least one fiber Bragg grating in the at least one fiber optic, an optical coupler interconnected with the control apparatus and with the at least one fiber optic, a source interconnected with the control apparatus for sending a light signal through the at least one fiber optic, and a detector interconnected with the control apparatus and for detecting a signal reflected from the at least one fiber Bragg grating.

18. The system of claim 17 further comprising an isolator for preventing reflected light from entering the source.

19. The system of claim 17 wherein the at least one fiber optic is a plurality of fiber optics and the at least one fiber Bragg grating is a plurality of fiber Bragg gratings.

20. The system of claim 17 further comprising an acoustic transmitter interconnected with the control apparatus and disposed adjacent the wireline and past which the wireline is movable, the acoustic transmitter interconnected with the control apparatus and for transmitting an acoustic signal to the at least one fiber Bragg grating.

21. A method for obtaining data from within a wellbore, the method comprising running a cable into a wellbore that extends into the earth from an earth surface, the cable comprising wellbore cable apparatus having spaced apart ends including a first end and a second end, at least one fiber optic within the wellbore cable apparatus and extending therein from the first end of the wellbore cable apparatus to the second end thereof, and at least one fiber Bragg grating in the at least one fiber optic, sending a signal with signal transmission means to the at least one fiber Bragg grating, receiving the signal with signal reception means, and processing the signal to obtain the data.

22. The method of claim 21 wherein the data includes data related to length of the cable from the earth surface to the at least one fiber Bragg grating, wherein the at least one fiber Bragg grating is at least two fiber Bragg gratings including a first fiber Bragg grating and a second fiber Bragg grating below and spaced apart a distance d from the first fiber Bragg grating and wherein an acoustic transmitter is positioned adjacent the cable so that an acoustic signal is transmissible to and sensible by a fiber Bragg grating passing the acoustic transmitter, each fiber grating having an identifying fiber Bragg wavelength, the method further comprising sending an acoustic signal to the first fiber Bragg grating at a known location with respect to the acoustic transmitter and sensing the fiber Bragg wavelength thereof thereby identifying the first fiber Bragg grating, and calculating the distance from the acoustic transmitter to the second fiber Bragg grating based on the distance d and the known location of the first fiber Bragg grating.

23. The method of claim 21 wherein the at least one fiber Bragg grating is a plurality of spaced apart fiber Bragg gratings and wherein a final fiber Bragg grating in the at least one fiber optic is positioned at a lowest end thereof in the wellbore cable apparatus, and the method further comprising sending a signal from a broadband source down into the at least one fiber optic to the final fiber Bragg grating, and with a sensor at a known distance from the final fiber Bragg grating sensing a return signal from the final fiber Bragg grating to the sensor and a time of travel of the return signal from the final fiber Bragg grating to the sensor, calculating the length of the wireline cable apparatus from the sensor to the final fiber Bragg grating.

24. The method of claim 20 wherein the at least one fiber Bragg grating has an identifying fiber Bragg wavelength, the method further comprising sending an interrogating signal from a signal transmitter down to the at least one fiber Bragg grating, receiving with receiving apparatus a reflected signal from the at least one fiber Bragg grating, and calculating a difference between wavelength of the reflected signal and the fiber Bragg wavelength to determine a deviation from the fiber Bragg wavelength indicative of strain on the at least one fiber Bragg grating.

25. The method of claim 21 wherein the at least one fiber Bragg grating has a unique wavelength, the method including running the cable and the fiber Bragg grating to a known location down in the wellbore, at the known location, measuring the wavelength of the fiber Bragg grating, calculating a wavelength change between the fiber Bragg grating's unique wavelength and the wavelength measured at the known location down in the wellbore, and using the calculated change in wavelength, determining the temperature at the known location down in the wellbore.