Note: Descriptions are shown in the official language in which they were submitted.
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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
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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,
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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.
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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
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"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
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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
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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
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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
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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.
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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.
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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
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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
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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
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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
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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
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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
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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
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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
CA 02244829 1998-08-11
. 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
CA 02244829 1998-08-11
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
CA 02244829 1998-08-11
21
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
CA 02244829 1998-08-11
22
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
1552
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
CA 02244829 1998-08-11
23
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
CA 02244829 1998-08-11
24
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
CA 02244829 1998-08-11
. 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
25
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
2 2
Therefore from the equation for t2 - tl,
CA 02244829 1998-08-11
26
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
6
2. 90 x 10- * C
Lo = L + 2 * n - 3014 . 6 + 299. 8
0
- 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:
