Note: Descriptions are shown in the official language in which they were submitted.
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APPLICATION FOR UNITED STATES LETTERS PATENT
FOR
TIME AND DEPTH CORRECTION OF MWD AND WIRELINE
MEASUREMENTS USING CORRELATION OF SURFACE AND DOWNHOLE
MEASUREMENTS.
Inventors: Dmitriy Dashevskiy
Celle, Germany
Assignee: Baker Hughes Incorporated
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BACKGROUND OF THE INVENTION
1. Field of the Invention
[0001] This invention is related to methods for determining a depth at which
measurements are made by a downhole assembly based on surface estimates of the
depth
and surface and downhole measurements.
2. Description of the Related Art
[0002] In the rotary drilling of wells such as hydrocarbon wells, a drillbit
located at the
end of a drillstring is rotated so as to cause the bit to drill into the
formation. The rate of
penetration (ROP) depends upon the weight on bit (WOB), the rotary speed of
the drill
and the formation and also the condition of the drillbit. The earliest prior
art methods for
measuring ROP were based on monitoring the rate at which the drillstring is
lowered into
the well at the surface. However because the drill string, which is formed of
steel pipes,
is relatively l6ng, the elasticity or compliance of the string can result in
the actual ROP
being different from the rate at which the string is lowered into the hole.
Consequently,
the depth of the bottomhole assembly (BHA) that includes the drillbit is
different from
that which is estimated from surface measurements alone.
[0003] The BHA typically includes several formation evaluation (FE) sensors
that make
measurements of formation properties. These include, for example, density,
porosity,
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resistivity, and seismic velocities. Similar measurements may also be made
after the well
has been drilled by conveying logging instruments on a wireline or coiled
tubing.
Determination of properties of the formation is based upon evaluation of a
suite of logs
that are properly aligned in depth.
[0004] Due to their nature, all data from MWD tools are referenced to time,
i.e. it is
presumed to be known when every measured value was taken. For applications
involving
correlating different logs, it is necessary to know where the measurement was
taken. To
find out where it is necessary to know the wellbore profile, i.e., the
wellbore location in
space. The wellbore profile may be determined using suitable survey
instruments such as
accelerometers and/or gyroscopes.
[00051 It is also necessary to know the time-depth profile, i.e., where (with
respect to the
wellbore) the bit was located at each moment of time. Using the wellbore
profile and the
time-depth profiled, it is possible to place MWD measurements along the
wellbore and
hence in space.
[00061 The wellbore and time-depth profiles are known only with some finite
accuracy.
This affects the accuracy of the final logs. This is well known and there is
much effort
spent to ensure good quality surveys and depth measurements. There is another
problem
that has a strong impact on the accuracy of the final results. This problem
arises due to
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the fact that the timestamps on MWD data come from the clocks in MWD tools,
while
surface measurements have timestamps from the surface computer clock.
[0007] If the tool clock does not produce the same time as the surface clock
during the
whole run, then any attempt to use time-depth profiles (which are based on
surface time)
to convert from when to where will result in erroneous output. The error
depends on how
big this mismatch is, and due to the non linearity of the time-depth
transformation even
small time mismatches can result in noticeable changes to the logs (especially
time-based
logs).
[00081 US 6,837,105 to DiFoggio et al. discloses the use of a downhole atomic
clock for
maintaining synchronization with a surface clock for seismic while drilling
(SWD)
applications. Atomic clocks based on an atomic transition of rubidium, cesium
and/or
hydrogen can have drifts as small as 3 s per day. This kind of accuracy is
necessary for
SWD applications where errors of 1-2 ms in synchronization can be serious. For
determination of a time-depth profile, as in the present invention, an
accuracy 3 s is not
necessary. Even for a high rate of penetration (ROP) of 100 m/hr, an error of
1 second
translates into a depth error of less than 3 cm; for lower ROPs, the depth
error is even
smaller. Errors of the order of 3cm can be tolerated in correlation of
different logs.
Given the high cost of atomic clocks and the possible damage that can occur to
them in
the harsh drilling environment, it would be desirable to find alternate
methods of
determining proper alignment of logs.
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[0009] US 5,5 81,024 to Meyer et al. established proper alignment of logs use
of a
downhole computer and buffer storage within a MWD downhole subassembly to
process
data from the response of a plurality of sensors of different type. Sensor
measurements
are made essentially simultaneously. First, the sensor responses are
correlated to a
common reference point and reference vertical resolution. This correlation is
performed
using downhole models of the sensor responses stored within a downhole memory
associated with a downhole processor. In one embodiment, response models are
computed theoretically or are determined from sensor responses measured in
test
facilities with known environmental conditions. These sensor response models
are
initially stored within the downhole memory. As an alternate embodiment,
sensor
response models are calculated while drilling using the downhole computer and
sensor
responses in portions of the borehole where conditions are known. These models
are
then stored in the downhole memory and subsequently used for correlation in
the portions
of the borehole in which conditions are unknown. The depth and resolution
correlated
sensor responses are then processed, using combination sensor response models
stored
within the first storage means along with downhole computing means to obtain
logs of
formation parameters of interest as a function of depth within the borehole
which is
preferably a depth reference point.
[00101 The modeling is necessary in Meyer due to the fact that different
sensors have
different resolution in depth. This adds to the complexity of the problem that
must be
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solved. It would be desirable to have a relatively simple, inexpensive and
rugged
apparatus and method for determining the depth of a tool in a borehole. The
present
invention satisfies this need.
SUMMARY OF THE INVENTION
[0011] One embodiment of the present invention is a method of determining a
difference
between a first clock at a surface location and a second clock at a downhole
location of a
downhole assembly. First measurements of a first parameter of the downhole
assembly
are made at the surface location and a first time stamp is associated with the
first
measurements. Second measurements, similar to the first measurements, are made
of the
downhole assembly at the downhole location and a second time stamp is
associated with
the second measurements. The time difference is determined by matching a
feature of
the first measurements with a corresponding feature of the second
measurements. The
first and second measurements may be a rotational speed of a drillstring, a
torque
measurement and/or a pressure measurement. The determined time differences are
used
to correct formation evaluation and other downhole sensor measurements to a
corrected
time.
[0012] Another embodiment of the present invention is a measurement while
drilling
(MWD) system that includes a first clock at a surface location and a second
clock on a
bottomhole assembly (BHA) at a downhole location in a borehole in an earth
formation.
The second clock may have a time difference relative to the first clock. The
system
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further includes a processor which determines the time difference from first
measurements of a first parameter of the MWD system at the surface location
and second
measurements similar to the first measurements at the downhole location. The
time
difference is obtained by matching a feature of the first measurements with a
corresponding feature of the second measurements. The first and second
measurements
may be of rotational speed or torque.
[0013] Another embodiment of the invention is a computer readable medium for
use
with a measurement while drilling (MWD) system. The MWD system includes a
first
clock at a surface location a second clock on a bottomhole assembly (BHA) at a
downhole location in a borehole in an earth formation. The second clock has a
time
difference relative to the first clock. The medium includes instructions which
enable
determining the time difference from first measurements of a first parameter
of the MWD
system at the surface location and second measurements similar to the first
measurements
at the downhole location. The determination is done by matching a feature of
the first
measurements with a corresponding feature of the second measurements. The
medium
may be selected from the group consisting of (i) a ROM, (ii) an EPROM, (iii)
an
EAROM, (iv) a Flash Memory, and, (v) an Optical disk.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] The present invention is best understood with reference to the
accompanying
figures in which like numerals refer to like elements and in which:
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FIG. 1 (Prior Art) shows a schematic diagram of a drilling system having
downhole
sensor systems and accelerometers;
FIGS. 2a and 2b are plots of surface measurements and downhole measurements of
rotational speed at two different times of drilling;
FIG. 3 a is a plot of the time difference between the surface and downhole
rotational
speed as a function of drilling time;
FIG. 3b is a plot of the time difference between surface and downhole torque
measurements as a function of drilling time;
FIGs. 4a and 4b show the data of Figs. 2a and 2b after correcting for the time
shift;
FIG. 5 shows the method of conversion of time-based memory data to depth-based
log;
FIG. 6 shows the correction of misalignment between FE measurements and
drilling
measurements using the determined time shift;
FIG. 7 shows the determination of time since drilled; and
FIG. 8 shows the errors in time based logs without applying the time
corrections.
DETAILED DESCRIPTION OF THE INVENTION
[0015] FIG. 1 shows a schematic diagram of an exemplary drilling system 10
having a
downhole assembly containing an acoustic sensor system and surface devices.
This is a
modification (discussed below) of the device disclosed in US Patent 6 088 294
to Leggett
et al. As shown, the system 10 includes a conventional derrick 11 erected on a
derrick
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floor 12 which supports a rotary table 14 that is rotated by a prime mover
(not shown) at
a desired rotational speed. A drill string 20 that includes a drill pipe
section 22 extends
downward from the rotary table 14 into a borehole 26. A drill bit 50 attached
to the drill
string downhole end disintegrates the geological formations when it is
rotated. The drill
string 20 is coupled to a drawworks 30 via a kelly joint 21, swivel 28 and
line 29 through
a system of pulleys 27. During drilling operations, the drawworks 30 is
operated to
control the weight on bit and the rate of penetration of the drill string 20
into the borehole
26. The operation of the drawworks 30 is well known in the art and is thus not
described
in detail herein.
[0016] During drilling operations a suitable drilling fluid (commonly referred
to in the art
as "mud") 31 from a mud pit 32 is circulated under pressure through the drill
string 20 by
a mud pump 34. The drilling fluid 31 passes from the mud pump 34 into the
drill string
via a desurger 36, fluid line 38 and the kelly joint 21. The drilling fluid is
discharged
15 at the borehole bottom 51 through an opening in the drill bit 50. The
drilling fluid
circulates uphole through the annular space 27 between the drill string 20 and
the
borehole 26 and is discharged into the mud pit 32 via a return line 35.
Preferably, a
variety of sensors (not shown) are appropriately deployed on the surface
according to
known methods in the art to provide information about various drilling-related
20 parameters, such as fluid flow rate, weight on bit, hook load, etc.
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[0017] A surface control unit 40 receives signals from the downhole sensors
and devices
via a sensor 43 placed in the fluid line 38 and processes such signals
according to
programmed instructions provided to the surface control unit. The surface
control unit
displays desired drilling parameters and other information on a
display/monitor 42 which
information is used by an operator to control the drilling operations. The
surface control
unit 40 contains a computer, memory for storing data, data recorder and other
peripherals.
The surface control unit 40 also includes models and processes data according
to
programmed instructions and responds to user commands entered through a
suitable
means, such as a keyboard. The control unit 40 is preferably adapted to
activate alarms
44 when certain unsafe or undesirable operating conditions occur. The surface
control
unit also includes a surface clock (not shown).
[0018] Optionally, a drill motor or mud motor 55 coupled to the drill bit 50
via a drive
shaft (not shown) disposed in a bearing assembly 57 rotates the drill bit 50
when the
drilling fluid 31 is passed through the mud motor 55 under pressure. The
bearing
assembly 57 supports the radial and axial forces of the drill bit 50, the
downthrust of the
drill motor 55 and the reactive upward loading from the applied weight on bit.
A
stabilizer 58 coupled to the bearing assembly 57 acts as a centralizer for the
lowermost
portion of the mud motor assembly.
[0019] The downhole subassembly 59 (also referred to as the bottomhole
assembly or
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"BHA"), which contains the various sensors and MWD devices to provide
information
about the formation and downhole drilling parameters and the mud motor, is
coupled
between the drill bit 50 and the drill pipe 22. The downhole assembly 59
preferably is
modular in construction, in that the various devices are interconnected
sections so that the
individual sections may be replaced when desired.
[0020] Still referring to FIG. 1, the BHA also preferably contains sensors and
devices in
addition to the above-described sensors. Such devices may include a device for
measuring the formation resistivity near and/or in front of the drillbit 50, a
gamma ray
device for measuring the formation gamma ray intensity and devices for
determining the
inclination and azimuth of the drill string 20. The formation resistivity
measuring device
64 is may be coupled above the lower kick-off subassembly 62 that provides
signals,
from which resistivity of the formation near or in front of the drill bit 50
is determined.
A dual propagation resistivity device ("DPR") having one or more pairs of
transmitting
antennae 66a and 66b spaced from one or more pairs of receiving antennae 68a
and 68b
may be used. Magnetic dipoles are employed which operate in the medium
frequency
and lower high frequency spectrum. In operation, the transmitted
electromagnetic waves
are perturbed as they propagate through the formation surrounding the
resistivity device
64. The receiving antennae 68a and 68b detect the perturbed waves. Formation
resistivity is derived from the phase and amplitude of the detected signals.
The detected
signals are processed by a downhole circuit that is preferably placed in a
housing above
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the mud motor 55 and transmitted to the surface control unit 40 using a
suitable telemetry
system 72.
[0021] The inclinometer 74 and gamma ray device 76 are suitably placed along
the
resistivity measuring device 64 for respectively determining the inclination
of the portion
of the drill string near the drill bit 50 and the formation gamma ray
intensity. Any
suitable inclinometer and gamma ray device, however, may be utilized for the
purposes
of this invention. In addition, an azimuth device (not shown), such as a
magnetometer or
a gyroscopic device, may be used to determine the drill string azimuth. Such
devices are
known in the art and are, thus, not described in detail herein. In the above-
described
configuration, the mud motor 55 transfers power to the drill bit 50 via one or
more
hollow shafts that run through the resistivity measuring device 64. The hollow
shaft
enables the drilling fluid to pass from the mud motor 55 to the drill bit 50.
In an alternate
embodiment of the drill string 20, the mud motor 55 may be coupled below
resistivity
measuring device 64 or at any other suitable place.
[0022] The drill string 20 contains a modular sensor assembly, a motor
assembly and
kick-off subs. In a preferred embodiment, the sensor assembly includes a
resistivity
device, gamma ray device and inclinometer, all of which are in a common
housing
between the drill bit and the mud motor. Such prior art sensor assemblies
would be
known to those versed in the art and are not discussed fiuther.
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[0023] The downhole assembly of the present invention includes a MWD section
which
may contain a nuclear formation porosity measuring device, a nuclear density
device and
an acoustic sensor system placed above the mud motor 55 for providing
information
useful for evaluating and testing subsurface formations along borehole 26. The
present
invention may utilize any of the known formation density devices. Any prior
art density
device using a gamma ray source may be used. In use, gamma rays emitted from
the
source enter the formation where they interact with the formation and
attenuate. The
attenuation of the gamma rays is measured by a suitable detector from which
density of
the formation is determined.
[0024] The porosity measurement device preferably is the device generally
disclosed in
U.S. Pat. No. 5,144,126, which is assigned to the assignee hereof and which is
incorporated herein by reference. This device employs a neutron emission
source and a
detector for measuring the resulting gamma rays. In use, high energy neutrons
are
emitted into the surrounding formation. A suitable detector measures the
neutron energy
delay due to interaction with hydrogen and atoms present in the formation.
Other
examples of nuclear logging devices are disclosed in U. S. Pat. Nos. 5,126,564
and
5,083,124.
[0025] The above-noted devices transmit data to the downhole telemetry system
72,
which in turn transmits the received data uphole to the surface control unit
40. The
downhole telemetry also receives signals and data from the uphole control unit
40 and
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transmits such received signals and data to the appropriate downhole devices.
The
present invention preferably utilizes a mud pulse telemetry technique to
communicate
data from downhole sensors and devices during drilling operations. A
transducer 43
placed in the mud supply line 38 detects the mud pulses responsive to the data
transmitted by the downhole telemetry 72. Transducer 43 generates electrical
signals in
response to the mud pressure variations and transmits such signals via a
conductor 45 to
the surface control unit 40. Other telemetry techniques such electromagnetic
and
acoustic techniques or any other suitable technique may be utilized for the
purposes of
this invention. The BHA also includes a downhole processor and a downhole
clock (not
shown) at convenient locations.
[0026] In operation, MWD data are collected and stored in the downhole memory
during
the run. The following procedure has been commonly used in the past:
1. Synchronize all surface computers;
2. Before the run synchronize the tool clock to the surface computer;
3. Dump memory with the same computer after the run. During the dump
procedure, the time of the surface computer is compared to the time of the
tool
and a found mismatch is saved along with the memory data;
4. This saved mismatch is used during processing of memory data as a default
value
for time correction; and
5. The timestamps of memory data is shifter by the specified value.
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[0027] Unfortunately this way of "correcting" for a time mismatch does not
provide a
good correction, as the mismatch is not constant during the run. This can be
easily
observed by plotting the same parameter measured on the surface and downhole.
By
measuring the same parameter with the same resolution at the surface and
downhole, the
problem of resolution matching discussed in Meyer is avoided. Fig. 2a shows
the surface
measured rotational speed in RPM 151 and the downhole measured rotational
speed 153.
As expected, the surface speed is quite uniform, but the downhole speed is
somewhat
irregular. The main cause for the irregularity is possible sticking and
slipping of the
drillstring inside the borehole. Torsional waves travel quite fast in the
drill string and we
should see changes in the downhole RPM within few seconds after RPM is changed
on
the surface. Such a difference is noted, and is indicated by the time 155 with
a value of
approximately 80 seconds. An accurate estimate of this time difference may be
readily
obtained by performing a cross-correlation of the smoothed downhole curve with
the
surface curve 151. It should be noted that the use of surface and downhole
measurements
of RPM is for exemplary purposes only, and the method of the present invention
is
applicable for any two types of measurements that are similar to each other.
In this
regard, the term "similar' is intended to mean having matching features.
[0028] Fig. 2b shows similar plots of surface rotational speed 151' and
downhole
rotational speed 153' later in the drilling of the same well. The estimated
time shift 155'
is now only around 40 seconds. Note the difference in time scales between Fig.
21 and
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Fig. 2b. It is thus clear that the correction procedure outlined above would
not work with
a constant time shift.
[0029] Turning now to Fig. 3a, the results of using a time varying time shift
based on a
cross-correlation of the surface and downhole measurements of rotational speed
from
Figs. 2a, 2b are shown. The curve 201 is the determined time shift, 203 is a
linear fit to
201 and 205 is the difference between the determined time shift and the linear
fit
Obviously there is some noise in the downhole measurements and therefore they
should
be approximated first by a smooth curve before using them for time correction.
As a first
approximation a linear time correction (linear time "stretching") is a good
approximation.
In an alternate embodiment of the invention, different smoothing, such as a
higher order
polynomial may be used. Fig. 3b shows similar results for torque measurements:
221 is
the determined time shift between surface torque measurements and downhole
torque
measurements while 223 is a linear fit to 221. The results are similar to
those in Fig. 3a.
Another measurement that can be used is the pressure. For example, when a
drill pipe is
being added to the drillstring, the mud pump is turned off. It takes a
determinable time
for the resulting pressure change to propagate down the borehole and reach the
BHA.
Any time difference over and above the determinable time is attributable to
the clock.
[0030] As would be known to those versed in the art, the surface rotary speed
is
determined largely by the speed of the drive motor at the surface. The rotary
speed
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downhole, on the other hand, is more affected by stick-slip effects and will
thus be more
erratic. As long as there is no bit bounce at the bottom, a smoothing is
appropriate.
[0031] Turning now to Fig. 4a, the results of shifting the downhole speed
measurements
of Fig. 2a (earlier in the drilling) based on the linear shift 203 of Fig. 3
are shown. The
downhole speed 253 tracks the surface speed 251 quite well. Similarly, Fig. 4b
shows
the results of shifting the downhole speed measurements of Fig. 2b (later in
the drilling)
based on the linear shift 203 of Fig. 3. As in Fig. 4a, the time shifted
downhole speed
253' matches the surface speed 251' quite well.
[0034] We next examine the effect of the time shift (of the order of one
minute or so) on
formation evaluation (FE) logs in depth. The FE logs are, as noted above,
recorded in
time and stored in a memory in the BHA. Referring to Fig. 5, an exemplary FE
log 301
is shown. This is a function of time, and at a selected time such as 303, the
FE log has a
value of 311. The time-depth profile from surface measurements is depicted by
305. In
the example shown, there is a time period when the drillbit was backed up from
the
bottom of the hole as seen in the negative slope of 305. At the time 303, the
surface
measurements would indicate a depth of the drillbit denoted by 307. The FE
sensor,
which is at a known distance above the drillbit would then be at the depth
309. The value
311 is assigned to the FE curve at depth 309 to give the point 313. Repeating
this for
other values 303 of the FE time produces the curve 321.
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[0035] Turning to Fig. 6, an exemplary FE log 351 (density, for this example)
is shown
as a function of depth using the method of Fig. 5 and without applying the
time shift
estimated from Fig. 3. Also shown in Fig. 6 are the weight on bit (WOB) 355,
the rotary
speed (RPM) 357, and the ROP 359. The WOB, RPM and ROP all shown a layer at
the
depth interval denoted by 363 which corresponds to a significant change in
drilling
conditions. The drilling parameter logs have a scale chosen to make the
comparison with
the density logs clearer. The density change corresponding to this drilling
change is
shifted by about 6 ft. in the curve 351 relative to the change in drilling
conditions. The
density change was due to a shale stringer within a sand layer.
[0036] After applying the time shift to the FE-time curve and converting it to
depth gives
the curve 361. There is now a good match between the depth of the stringer
seen on the
density curve and the change in drilling conditions 363 due to the stringer.
Similar
observations may be made about a second stringer 365 that can be seen in Fig.
6.
[0037] The mismatch is exacerbated if, as is common practice, FE logs are
examined at
the wellsite in the form of time displays. The correction of the logs to a
common time
base is first discussed with reference to Fig. 7. Suppose that an MWD data
point is
measured at some time tm (403). Using the time-depth profile 409 one can find
depth of
the bit db;t 405 at time tm. Formation evaluation (FE) sensors are some meters
behind the
bit. Subtracting sensor offset from db;t one will find the depth of the sensor
ds 407 when
measurement was done. Using ds one can find time tp 401 when bit was at this
depth.
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Difference between tm and tP (421) is called time since drilled (TSD) and is
used to plot
FE data alongside drilling data on time-based logs. Of course, the TSD value
is not a
constant during the run and is computed for each data point. The FE log 411 is
thus
converted to 413. The results of this conversion of an FE log and a comparison
with
drilling logs in time is discussed next.
[0038] Shown in Fig. 8 is the FE log displayed in time 451 without and with
453 the
time shift. The curve 455 is the WOB, 457 is the drilling activity code, 459
is the RPM
and 459 is the ROP. Looking at the figure, it would not be clear whether the
"spike" 471
is a spike in the measurement due to noise (which it is not), or whether it is
a lithology
change (which it is).
[0039] It should be noted with respect to Fig. 6 that in the example shown,
the ROP is
highly correlated with the WOB. US 6769407 to Dubinsky et al., having the same
assignee as the present invention and the contents of which are incorporated
herein by
reference, teaches a method of determining ROP from downhole accelerometer
measurements. Accordingly, the method of the present invention is not limited
to
correlating downhole RPM measurements with surface RPM measurements, and other
downhole measurements, such as ROP determined from accelerometer measurements
may also be used.
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[0041] By using the method of the present invention, the FE sensor
measurements in
depth can be properly aligned with sensor measurements made with wireline
logging
tools or with measurements made using sensors conveyed on a slickline. This
greatly
facilitates the interpretation of formation properties by having redundant
measurements
and/or additional measurements between MWD, wireline and slickline sensors.
Slickline
measurements have the same clock problems as MVVD measurements since the
downhole
clock and sensors are isolated from the surface system and do not even have
the limited
telemetry capabilities of MWD systems. The proper alignment in depth of
measurements
made with different sensors at different times having possibly different
resolution and
different depths of investigation makes it possible to use the method
disclosed in US
6344746 to Chunduru et al, having the same assignee as the present invention
and the
contents of which are incorporated herein by reference.
[0042] In some situations, different FE sensors may be at different parts of
the BHA and
have different time clocks with different drifts. The method described above
provides a
framework which makes it possible to compare the FE sensor data not only with
drilling
data but also with each other.
[0043] The processing of the data to apply the various corrections may be
accomplished
in whole or in part by a downhole processor and in whole or in part by a
surface
processor or a combination of a. Implicit in the control and processing of the
data is the
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use of a computer program implemented on a suitable machine readable medium
that
enables the processor to perform the control and processing. The machine
readable
medium may include ROMs, EPROMs, EAROMs, Flash Memories and Optical disks.
[0044] While the foregoing disclosure is directed to the preferred embodiments
of the
invention, various modifications will be apparent to those skilled in the art.
It is intended
that all variations within the scope and spirit of the appended claims be
embraced by the
foregoing disclosure.
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