U.S. patent application number 11/835241 was filed with the patent office on 2009-09-10 for apparatus and method for determining thermal neutron capture cross section of a subsurface formation from a borehole using multiple detectors.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. Invention is credited to Allen Gilchrist, Darryl E. Trcka.
Application Number | 20090224146 11/835241 |
Document ID | / |
Family ID | 34381346 |
Filed Date | 2009-09-10 |
United States Patent
Application |
20090224146 |
Kind Code |
A1 |
Gilchrist; Allen ; et
al. |
September 10, 2009 |
Apparatus and Method for Determining Thermal Neutron Capture Cross
Section of a Subsurface Formation From a Borehole Using Multiple
Detectors
Abstract
A well logging instrument including a plurality of detectors
having different precisions and accuracies, the more precise
detectors generally having lower accuracies. The detectors are
responsive to the interaction of radiation from a suitable source
on the instrument with earth formations. Outputs from the plurality
of detectors are smoothed and combined to provide processed
measurements with improved accuracy and precision.
Inventors: |
Gilchrist; Allen; (Houston,
TX) ; Trcka; Darryl E.; (Houston, TX) |
Correspondence
Address: |
MADAN & SRIRAM, P.C.
2603 AUGUSTA DRIVE, SUITE 700
HOUSTON
TX
77057-5662
US
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
34381346 |
Appl. No.: |
11/835241 |
Filed: |
August 7, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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10955867 |
Sep 30, 2004 |
7253402 |
|
|
11835241 |
|
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60507383 |
Sep 30, 2003 |
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Current U.S.
Class: |
250/269.7 |
Current CPC
Class: |
G01V 5/102 20130101 |
Class at
Publication: |
250/269.7 |
International
Class: |
G01V 5/10 20060101
G01V005/10 |
Claims
1. A method for determining a parameter of interest of an earth
formation with a logging tool having an energy source and a
plurality of detectors for making measurements resulting from
interaction of said energy source with said earth formation, the
method comprising: (a) making a first measurement indicative of
said parameter of interest at a first of said plurality of
detectors, said first measurement having a first precision; (b)
making a second measurement indicative of said parameter of
interest at a second of said plurality of detectors, said second
measurement having a second precision not greater than said first
precision; (c) combining said first and second measurements using a
standard deviation of the measurements for each of the detectors to
give a processed measurement having a higher precision than the
first measurement; and (d) recording the processed measurement on a
suitable medium.
2. The method of claim 1 wherein said energy source comprises a
source of radiation.
3. The method of claim 1 wherein said first measurement has a first
accuracy, said second measurement has a second accuracy not less
than said first accuracy, and wherein said processed measurement
has an accuracy at least the same as said second accuracy.
4. The method of claim 3 further comprising: making a third set of
measurements indicative of said parameter of interest, said third
measurements having a precision intermediate to said first and
second precisions and a third accuracy intermediate to said first
and second accuracies; and wherein combining said first and, second
measurements further comprises combining the third measurement with
the first and second measurements.
5. The method of claim 4 wherein said first measurement is made
with a first detector having a first distance from said source, and
said second measurements are made with a second detector having a
second distance from said source greater than said first
distance.
6. The method of claim 5 wherein said third measurement is made
with a third detector having a distance from said source that is
intermediate to said first and second distances.
7. The method of claim 1 wherein said measurements comprise gamma
ray counts.
8. The method of claim 1 wherein said measurements comprise neutron
counts.
9. The method of claim 4 wherein combining said first, second and
third measurements further comprises forming a weighted sum of said
first, second and third measurements.
10. The method of claim 1 wherein combining said first and second
measurements further comprises filtering said first measurement to
give filtered measurements having a resolution that is
substantially equal to a resolution of said second measurement.
11. The method of claim 4 wherein combining said first, second and
third measurements further comprises filtering said first and third
measurements to give output measurements having a resolution that
is substantially equal to a resolution of said second
measurement.
12. The method of claim 15 further comprising determining said
parameter of interest from said processed measurements.
13. The method of claim 1 wherein said parameter of interest is
selected from: (i) a porosity of said formation, and (ii) a density
of said formation.
14. The method of claim 1 wherein said first and second detectors
are at the same spacing from said source, and wherein said second
detector is sampled more frequently than said first detector.
15. An apparatus for determining a parameter of interest of an
earth formation comprising: (a) a logging tool configured to be
conveyed into a borehole in said earth formation, said logging tool
including a source which propagates energy into said earth
formation; (b) a first detector on said logging tool spaced apart
from the source at a first distance, said first detector configured
to make a first measurement indicative of an interaction of said
energy with said earth formation, said first measurement having a
first precision; (c) a second detector on said logging tool spaced
apart from the source at a second distance greater than the first
distance, said second detector configured to make a second
measurement indicative of said parameter of interest, said second
measurement having a second precision not greater than said first
precision; and (d) a processor configured to combine said first and
second measurements using a standard deviation of the measurements
for each of the detectors to give a processed measurement having a
higher precision than the first measurement.
16. The apparatus of claim 15 wherein said second measurement has a
second accuracy not less than a first accuracy of said first
measurement, and wherein said processed measurement has at least
the same accuracy of the second measurement.
17. The apparatus of claim 16 further comprising a memory device
configured to store said first and second measurements.
18. The apparatus of claim 15 wherein said source comprises a
pulsed neutron source.
19. The apparatus of claim 15 further comprising a third detector
on said logging tool spaced apart from said source at a third
distance intermediate to said first and second distances, and
wherein said processor is further configured to combine
measurements made by said third detector with measurements made by
said first and second detectors.
Description
CROSS-REFERENCES TO RELATED APPLICATIONS
[0001] This application is a continuation of U.S. patent
application Ser. No. 10/955,867, now U.S. Pat. No. 7,253,402, which
claimed priority from U.S. provisional patent application Ser. No.
60/507,383.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The invention is related to the field of pulsed neutron well
logging. More specifically, the invention is an apparatus and
method for improving accuracy and precision of capture
cross-section measurements.
[0004] 2. Description of the Related Art
[0005] Pulsed neutron well logging instruments are known in the art
for determining the macroscopic thermal neutron capture
cross-section of earth formations penetrated by a wellbore. Typical
pulsed neutron instruments include a controllable source of
high-energy neutrons and one or more gamma ray radiation detectors
positioned at spaced apart locations from the neutron source. The
source is periodically activated to emit controlled-duration
"bursts" of high-energy neutrons into the earth formations
surrounding the well borehole. These neutrons interact with the
atomic nuclei of the materials in the earth formations, losing
energy with each interaction until the neutrons reach the thermal
energy level (defined as having a most likely energy of about 0.025
electron volts). Depending on the material composition of the earth
formations proximal to the instrument, the thermal neutrons can be
absorbed (captured), at various rates by certain types of atomic
nuclei in the earth formations. When one of these atomic nuclei
captures a thermal neutron, it emits a gamma ray, which is referred
to as a "capture gamma ray".
[0006] The rate at which the capture gamma rays are emitted, with
respect to the elapsed time after the end of the neutron "burst"
depends on, among other things, the relative concentration per unit
volume in the earth formations of those atomic nuclei which have a
relatively large tendency to absorb thermal neutrons and emit
capture gamma rays in response. This tendency is referred to as the
thermal neutron capture cross-section.
[0007] The capture cross section, designated as .SIGMA., of the
formation is determined by sending a burst of neutrons from the
tool and watching the decline of the gamma ray count rate with time
as the neutrons are captured by the surrounding materials (neutron
capture) and as they diffuse farther away (neutron diffusion).
.SIGMA. is inferred from this observed decline in the gamma ray
count rate versus time. However, in addition to the neutron
capture, two key environmental effects contribute to the observed
decline, or decay rate: diffusion and the so-called "borehole
contamination." These effects need to be carefully characterized in
order to determine the correct .SIGMA. throughout the wide range of
operating conditions typically encountered in the oilfield. These
effects are controlled by parameters which include borehole size,
casing size, casing weight, borehole fluid salinity, porosity, and
lithology.
[0008] Some approaches to handling these environmental effects have
been described in the prior art literature. See, for e.g.,
Steinman, et al. "Dual-Burst Thermal Decay Time Logging
Principles," 1986 SPE Annual Technical conference and Exhibition,
New Orleans, La., (Oct. 5-8, 1986), paper SPE 15437; Smith, et al.,
"Obtaining Intrinsic Formation Capture Cross Sections with Pulsed
Neutron Capture Logging Tools," Transactions of the 29.sup.th
Annual SPWLA Symposium, San Antonio, Tex. (Jun. 5-8, 1988), paper
SS; Murdoch, et al., "Diffusion Corrections to Pulsed Neutron
Capture Logs: Methodology," Transactions of the 31.sup.st Annual
SPWLA Symposium, Lafayette, La. (Jun. 24-27, 1990), paper Q; and
Odom et al., "Quantitative Use of Computer Models in Calibration of
the Computalog Pulsed Neutron Thermal Decay, Transactions of the
33.sup.rd Annual SPWLA Logging Symposium, Oklahoma City, Okla.
(Jun. 14-17, 1992), paper P.
[0009] Under certain wellbore conditions, it is difficult to
determine the fractional saturation of oil or gas by processing the
capture gamma ray measurements according to methods known in the
art for determining the thermal neutron capture cross-section,
.SIGMA..sub.F, of the earth formation of interest. Several factors
contribute to this difficulty. First, the well logging instrument
is typically inserted into a wellbore which is filled with liquid.
At the time the pulsed neutron instrument is typically used, the
wellbore generally has inserted therein a steel liner or casing.
The liner or casing is generally held in place by cement filling
the annular space between the wellbore wall and the exterior of the
liner or casing. As high-energy neutrons leave the neutron source
in the logging instrument, the mud in the wellbore has the effect
of rapidly moderating (or slowing down) the high-energy neutrons to
the thermal level due to of the high concentration of hydrogen
nuclei in the mud.
[0010] In general, the relative numbers of thermal neutrons
("population") at any particular time after a neutron burst, or
thermal neutrons in the wellbore and in the earth formations
proximal to the wellbore, will depend on the porosity and on the
hydrogen nucleus concentration within the earth formation. This
population can be "captured," or absorbed by nuclei of various
chemical elements in the wellbore and formations, at a rate which
depends upon the relative concentration and on the thermal neutron
capture cross-section of these elements. In wellbores and in earth
formations, some of the more common elements having high thermal
neutron cross-sections include chlorine, hydrogen, iron, silicon,
calcium, boron, and sulfur. As determined from measurements of
capture gamma rays made by the well logging instrument, the thermal
neutron decay time (neutron lifetime), represents combined effects
of the thermal neutron capture cross-section in each of several
regions within the wellbore as well as in the earth formations
proximal to the wellbore. These regions include the instrument
itself, the fluid in the wellbore, the steel casing, the cement,
the earth formations radially proximal to the wellbore wall (which
may have been infiltrated by fluid from within the wellbore), and
the earth formations radially more distal from the wellbore wall
(which have minimal infiltration from the fluid in the
wellbore).
[0011] Several prior art are aimed at improving measurements in
capture cross-section logging. A method and apparatus employing a
source and two detectors are discussed, for example, in U.S. Pat.
Nos. 4,645,926 and 4,656,354, both issued to Randall. A subsurface
instrument includes a long-spaced (LS) and short-spaced (SS)
detector for detecting natural or induced gamma ray emissions from
subsurface formations. The detectors produce electrical pulses,
with each pulse corresponding in time with the incidence of a
corresponding gamma ray on the detector and having an analog
voltage amplitude correlative of the gamma ray. A method is
discussed in Randall '354 for determining presence of a gas by
comparing first and second parameters obtained at the detectors.
The first parameter is indicative of a count of detected
impingements of primarily inelastic gamma radiation upon a
detector. The second parameter is indicative of a count of detected
impingements of primarily capture gamma radiation upon a detector.
Randall '926 discusses a method of determining a parameter of the
borehole, wherein primarily inelastic gamma radiation is normalized
upon impingement on a detection means.
[0012] In U.S. Pat. No. 4,668,863, issued to Gray, et al., an
apparatus is used to analyze and process parameters including, for
example, the macroscopic thermal neutron absorption capture
cross-section of the formation at borehole elevations corresponding
to the locations from which such spectra are derived. For acquiring
temporal spectral data, a multi-channel scale section is provided
which includes a channel number generator which produces a
numerical sequence of memory address codes corresponding to a
sequence of adjacent time windows. A suitable memory device is part
of the downhole apparatus. Each code uniquely defines a start time,
whereby the windows collectively comprise the time interval of the
desired spectrum. Each time a gamma ray pulse is detected, the
memory address generated at that time addresses a corresponding
memory location and increments the count value resident therein. At
the conclusion of the time spectrum interval of interest, the
memory locations may be interrogated by the CPU and the resultant
spectral data analyzed, transmitted to the surface, or presented
visually as a gamma ray emission count versus time plot.
Correlation is made of detection signals in response to impingement
of gamma radiation upon first and second detectors.
[0013] U.S. Pat. No. 5,973,321, issued to Schmidt, discusses a
method for determining the fractional amounts and the thermal
neutron capture cross-sections of various regions in a wellbore and
regions in earth formations in the vicinity of the wellbore, each
having a distinct mean neutron decay time or macroscopic thermal
neutron capture cross-section. The method includes generating a
data kernel which is made up of representors (models), or potential
decay components of the wellbore and of the earth formations in the
vicinity of the wellbore. A thermal neutron decay spectrum is
measured by a pulsed neutron instrument including a controllable
source of high-energy neutrons and one or more gamma ray detectors
at spaced-apart locations from the source. The decay spectrum
measured by the instrument is inverted to determine model
parameters by which the individual representors are scaled so that
when combined, the scaled representors most closely match the
measured decay spectrum.
[0014] U.S. Pat. No. 5,808,298, issued to Mickael, discusses a
method for determining the oil saturation in an earth formation
penetrated by a wellbore. Measurement of the relative amounts of
carbon and oxygen in the wellbore and formation are made by
spectral analysis of neutron-induced inelastic gamma rays detected
from the earth formation at spaced-apart locations. The method
includes calculating an apparent oil holdup in the wellbore at each
one of the spaced-apart locations from the measurements of the
relative amounts of carbon and oxygen. A corrected oil holdup is
calculated in the wellbore from differences between the apparent
holdups determined at each of the spaced-apart locations. An
apparent oil saturation in the formation is determined at each of
the spaced-apart locations from the relative amounts of carbon and
oxygen and the corrected oil holdup. A corrected formation oil
saturation is determined from differences between the apparent oil
saturations at each of the spaced apart locations.
[0015] Plasek et al., 1995, "Improved Pulsed Neutron Capture
Logging With Slim Carbon-Oxygen Tools: Methodology," SPE Annual
Technical Conference & Exhibition, Dallas, Tex., Oct. 22-25,
1995, paper SPE 30598, discusses a method of carbon-oxygen ratio
determination using a reservoir saturation tool for determining
physical parameters of a formation. In one embodiment of the tool,
the source and detectors are cylindrically symmetrical. In an
alternate embodiment of the tool, the short-spaced detector is
positioned so as to face toward the borehole while the long-spaced
detector is positioned against a face of the borehole wall so as to
receive signals from inside a formation layer.
[0016] A need exists for improving a precision and accuracy of
parameter estimation obtained from earth formations. The present
invention fulfills this need.
SUMMARY OF THE INVENTION
[0017] The present invention is a method and apparatus for
determining a parameter of interest of an earth formation with a
logging tool having a source for irradiating said earth formation
and a plurality of detectors spaced apart from the source for
making measurements resulting from interaction of the radiation
with the earth formation. The parameter of interest may be a
density or porosity of the earth formation. In one embodiment of
the invention, a first and second set of measurements are made with
first and second detectors. The first detector has a higher
precision, higher resolution, and lower accuracy than the second
detector. The measurements of the first and second detectors are
combined to give measurements with improved accuracy and precision.
The combination is effected after filtering the first detector
measurements to match the resolution of the second detector. A
normalization factor for the first detector measurements is derived
from the combined measurement, and then applied to the first
detector measurements. A similar method is used when three
detectors of varying accuracy and precision are used for making
measurements. In another aspect, the invention is a system that
includes a conveyance device such as a wireline or a drilling
tubular for conveying a logging tool into a borehole, the logging
tool having a source for irradiating said earth formation and a
plurality of detectors spaced apart from the source for making
measurements resulting from interaction of the radiation with the
earth formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0018] The present invention is best understood with reference to
the attached drawings in which like numerals refer to like
elements, and in which:
[0019] FIG. 1 shows an illustration of an apparatus suitable for
use with the present invention;
[0020] FIG. 2 (prior art) is an overall schematic diagram of the
nuclear well logging system of the present invention; and
[0021] FIG. 3 shows a flow chart of the method of the present
invention.
DESCRIPTION OF PREFERRED EMBODIMENT
[0022] FIG. 1 shows an illustration of an apparatus suitable for
use with the present invention. The apparatus illustrated is that
of the Reservoir Performance Monitor (RPM) of Baker Atlas,
Incorporated. A measurement device 100 comprises a neutron source
101 and three axially spaced apart detectors described below. The
number of detectors shown in the embodiment of FIG. 1 is only
example of the number of detectors employed in an embodiment of the
present invention. It is not a limitation on the scope of the
present invention. The measurement device of the present invention
may comprise two or more detectors. The neutron source 101 may be
pulsed at different frequencies and modes for different types of
measurements. Detector short-spaced (SS) detector 105 is closest to
the source 101 The long-spaced (LS) detector is denoted by 106, and
the furthest detector 107 is referred to as the extra-large spaced
(XLS) detector. Fast neutrons (approximately 14 MeV) are emitted
from the source 101 and enter the borehole and formation, where
they undergo several types of interactions. During the first few
microseconds (.mu.s), before they lose much energy, some neutrons
are involved in inelastic scattering with nuclei in the borehole
formation and produce gamma rays. These inelastic gamma rays 120,
have energies that are characteristic of the atomic nuclei that
produced them. The atomic nuclei found in this environment include,
for example, carbon, oxygen, silicon, calcium, and some others.
[0023] Two or more gamma-ray detectors are employed, in one or more
modes of operation. Such modes include, but are not limited to, a
pulsed neutron capture mode, a pulsed neutron spectrometry mode, a
pulsed neutron holdup imager mode, and a neutron activation mode.
In a pulsed neutron capture mode, for example, the tool pulses at 1
kHz, and records a complete time spectrum for each detector. An
energy spectrum is also recorded for maintaining energy
discrimination levels. Time spectra from short-spaced and
long-spaced detectors can be processed individually to provide
traditional thermal neutron capture cross section information, or
the two spectra can be used together to automatically correct for
borehole and diffusion effects and produce results substantially
approximating intrinsic formation values.
[0024] In a pulsed neutron spectrometry mode, the instrument pulses
at 10 kHz, for example, and records full inelastic and capture
gamma ray energy spectra from each detector. These data are
processed to determine critical elemental ratios including
carbon/oxygen and calcium/silicon from the inelastic spectra and
silicon/calcium from the capture spectra. A pulsed neutron holdup
imager mode yields both energy spectra and time decay spectra from
each detector simultaneously. Measurements can be used to determine
holdups of gas, oil, and water. When combined with other production
logs, the measurements made herein can provide a comprehensive
production profile picture, even in deviated or horizontal wells. A
neutron activation mode provides water-flow measurements using one
of several data acquisition methods. Stationary measurements are
made in either of two modes, and measurements at different logging
speeds can be used to segregate different flow rates in either an
annulus or in an adjacent tubing string. Various spectra of count
rates from these can be used either individually or in combination
as needed for each measurement mode.
[0025] With the neutron generator turned off, the measurement
apparatus can also be used to detect the distribution of materials,
tagged with radioactive tracers, that are injected into the well
during well treatments. In this manner, the effectiveness of
operations such as hydraulic fracturing or gravel pack placement
can be evaluated.
[0026] In an embodiment of the present invention, a pulsed neutron
generator with improved reliability and higher output is coupled
with high-speed downhole microprocessor-controlled drivers and
detector electronics. The system supports multiple frequency
operation and different detection gate timings to make the
different measurements. The modes of operation can be selected from
the surface with no need to pull the tool out of the well.
[0027] After just a few .mu.s, most of the neutrons are slowed by
either inelastic or elastic scattering until they reach thermal
energies, about 0.025 eV. This process is illustrated schematically
in FIG. 1 as the sequence of solid arrows 110. At thermal energies,
neutrons continue to undergo elastic collisions, but they no longer
lose energy on average. A few .mu.s after the neutron generator
shuts off, this process is complete. Over the next several hundred
.mu.s, thermal neutrons are captured by nuclei of various
elements--again producing gammas rays, known as capture gamma rays
130. A capture gamma ray energy spectrum yields information about
the relative abundances of these elements.
[0028] The rate at which the thermal neutron population is captured
can be determined from the total number of capture gamma rays
recorded as a function of time. This time decay spectrum can
provide information about those elements with large cross sections
for (or high probabilities of) thermal neutron capture.
[0029] Typically, the precision and accuracy of a given detector
are dependent on the distance from the detector to the source. At
shorter distances, a significant number of received signals are
attributable to material residing in the borehole region, rather
than in the earth formation being investigated. The accuracy of
such a measurement at short source-detector distances is thereby
reduced. On the other hand, close proximity of a detector to a
source results in a high signal strength. This high signal strength
leads to a high degree of statistical precision of the measurement
taken at that short distance. At longer distances between detector
and source, an increased percentage of signals are obtained from
the earth formation, thereby leading to a higher degree of accuracy
of the measurement obtained. However, the number of signals
obtained by the detector is significantly reduced due to the
increased distance and diffusion processes. Lack of sufficient
signal strength yields a lower statistical precision of the
measurement.
[0030] In the present invention described above with reference to
FIG. 1, the SS detector 105 measures the received signals at a high
level of precision. As the source-detector spacing increases, this
level of precision drops, so that measurements at LS detector 106
are not as precise as the measurements from the SS detector. On the
other hand, measurements obtained at the SS detector are highly
perturbed by interaction with elements within the borehole.
Increasing the spacing between source and detector reduces the
perturbative effects of the borehole, thereby increasing the
accuracy of the measurement at the XLS detector 107. The logging
tool described above may be part of a system, such as that
illustrated in FIG. 2. The system shown in FIG. 2 is a prior art
system. Well 10 penetrates the earth's surface and may or may not
be cased depending upon the particular well being investigated.
Disposed within well 10 is subsurface well logging instrument 12.
The system diagramed in FIG. 2 is a microprocessor-based nuclear
well logging system using multi-channel scale analysis for
determining the timing distributions of the detected gamma rays.
Well logging instrument 12 includes long-spaced (LS) detector 14,
short-spaced (SS) detector 16 and pulses neutron source 18. In one
embodiment, LS and SS detectors 14 and 16 are comprised of
bismuth-germanate (BGO) crystals coupled to photomultiplier tubes.
To protect the detector systems from the high temperatures
encountered in boreholes, the detector system may be mounted in a
Dewar-type flask. Also, in the preferred embodiment, source 18
comprises a pulsed neutron source using a D-T reaction wherein
deuterium ions are accelerated into a tritium target, thereby
generating neutrons having an energy of approximately 14 MeV. The
filament current and accelerator voltage are supplied to source 18
through power supply 15. Cable 20 suspends instrument 12 in well 10
and contains the required conductors for electrically connecting
instrument 12 with the surface apparatus.
[0031] The outputs from LS and SS detectors 14 and 16 are coupled
to detector board 22, which amplifies these outputs and compares
them to an adjustable discriminator level for passage to channel
generator 26. Channel generator 26 is a component of multi-channel
scale (MCS) section 24 which further includes spectrum accumulator
28 and central processor unit (CPU) 30. As will be explained later,
MCS section 24 accumulates spectral data in spectrum accumulator 28
by using a channel number generated by channel generator 26 and
associated with a pulse as an address for a memory location. After
all of the channels have had their data accumulated, CPU 30 reads
the spectrum, or collection of data from all of the channels, and
sends the data to modem 32 which is coupled to cable 20 for
transmission of the data over a communication link to the surface
apparatus. Also to be explained later is the further function of
channel generator 26 in generating synchronization signals which
control the pulse frequency of source 18, and further functions of
CPU 30 in communicating control commands which define certain
operational parameters of instrument 12 including the discriminator
levels of detector board 22, and the filament current and
accelerator voltage supplied to source 18 by power supply 15.
[0032] The surface apparatus includes master controller 34 coupled
to cable 20 for recovery of data from instrument 12 and for
transmitting command signals to instrument 12. There is also
associated with the surface apparatus depth controller 36 which
provides signals to master controller 34 indicating the movement of
instrument 12 within well 10. The system operator accesses the
master controller 34 to allow the system operator to provide
selected input for the logging operation to be performed by the
system. Display unit 40 and mass storage unit 44 are also coupled
to master controller 34. The primary purpose of display unit 40 is
to provide visual indications of the generated logging data as well
as systems operations data. Storage unit 44 is provided for storing
logging data generated by the system as well as for retrieval of
stored data and system operation programs. A satellite link may be
provided to send data and or receive instructions from a remote
location.
[0033] In a well logging operation such as is illustrated by FIG.
2, master controller 34 initially transmits system operation
programs and command signals to be implemented by CPU 30, such
programs and signals being related to the particular well logging
operation. Instrument 12 is then caused to traverse well 10 in a
conventional manner, with source 18 being pulsed in response to
synchronization signals from channel generator 26. Typically,
source 18 is pulsed at a rate of 1000 bursts/second (1 KHz). This,
in turn, causes a burst of high energy neutrons on the order of 14
MeV to be introduced into the surrounding formation to be
investigated. In a manner previously described, this population of
high energy neutrons introduced into the formation will cause the
generation of gamma rays within the formation which at various
times will impinge on LS and SS detectors 14 and 16. As each gamma
ray thus impinges upon the crystal-photomultiplier tube arrangement
of the detectors, a voltage pulse having an amplitude related to
the energy of the particular gamma ray is delivered to detector
board 22. It will be recalled that detector board 22 amplifies each
pulse and compares them to an adjustable discriminator level,
typically set at a value corresponding to approximately 100 KeV. If
such pulse has an amplitude corresponding to an energy of at least
approximately 100 KeV, the voltage pulse is transformed into a
digital signal and passed to channel generator 26 of MCS section
24.
[0034] The system of the present invention may differ from the
prior art system in that three detectors may be used. This has been
discussed above. In addition, as would be known to those versed in
the art, many of the functions of the components described with
reference to FIG. 2 may be carried out by a processor. It should
also be noted that the system described in FIG. 2 involves
conveyance of the logging device into the well by a wireline.
However, it is envisaged that the logging device could be part of a
measurement while drilling (MWD) bottom hole assembly conveyed into
the borehole by a drilling tubular such as a drillstring or coiled
tubing.
[0035] In a multi-detector device, several measurements of capture
cross-sections can be obtained. These measurements can be combined
to create a combined capture cross-section:
.SIGMA..sub.comb=.omega..sub.1.SIGMA..sub.1+.omega..sub.2.SIGMA..sub.2+
(1)
where .SIGMA..sub.i is the capture cross-section measured at
detector i, and .omega..sub.i is a corresponding weight of the
i.sup.th capture cross-section. The weight of an individual capture
cross-section can be typically determined by a statistical
precision of the measurement. For example, the weight can be
inversely proportionally to the standard deviation of the
measurement at a given detector:
.omega. i = 1 .sigma. i 2 ( 2 ) ##EQU00001##
where .sigma. is the variance of the measurement of the i.sup.th
detector. This weighting is done currently, for example, for C/O
measurements. Variance can be measured in a variety of ways. As an
example, with the RPM system, .sigma. can be determined by
measuring an average arrival time of the gamma rays at the
detector, and relating this average time to a decay rate. The
average time technique is a remarkably robust and statistically
precise method of computing .SIGMA..
[0036] The computation of the true or "intrinsic" formation sigma
is complicated by the fact that the raw data from the instrument
contain contributions from the borehole as well as from the
formation. In general, the early part of the decay is most affected
by neutron absorption in the borehole and the late decay by
formation absorption, although they are not completely independent
of each other. That is, the borehole influences the formation decay
and the formation influences the borehole decay. A typical
computation of sigma minimizes the borehole influence by using a
late portion of the decay for the formation sigma calculation.
[0037] Combined pulsed neutron capture data from multiple detectors
can be used in such a way as to improve the statistical precision
and the accuracy of the measurement. The term "precision" refers,
in a general sense, to the repeatability of the measurements, i.e.,
a more precise sensing device will give the same value for repeated
measurements of the same parameter. The term "accuracy" refers to
how close the output of a sensing device is to the true value of
the quantity being measured. Thus, a precise measurement that has a
bias is not an accurate measurement.
[0038] In a preferred embodiment of the invention, a weighted
combination of data from two or more detectors is used to provide
measurements with statistical precision superior to any one of the
individual detectors alone. Such combinations will have measurement
characteristics that are somewhat different from those of any
individual detector alone. As discussed above, the XLS detector 107
achieves a higher degree of accuracy over the measured interval
than measurements of the SS 105 and LS 106 detector. The XLS 107
detector will also have a lower resolution and lower precision than
the LS and SS detectors. In the present invention, a measurement is
obtained with an accuracy of a measurement from the XLS detector
and a precision obtained from a weighted normalized
.SIGMA..sub.comb. This can be done in the manner described
next.
[0039] Turning now to FIG. 3, one embodiment of the invention is
shown. A first set of measurements, preferably the SS measurements,
are smoothed 401 by a suitable filtering operation to match the
resolution of a second set of measurements, preferably the XLS
measurements. The resulting smoothed SS measurements has an even
smaller standard deviation (higher precision) than the original SS
measurements. The smoothed measurements are then combined 403 with
a second set of measurements (preferably the XLS measurements)
using eq. (1) to give a combined measurement. This combined
measurement will be more accurate than the first measurements. U.S.
Pat. No. 4,794,792 to Flaum, et al, discusses a step similar to the
filtering carried out herein, but does not teach or suggest
combining the measurements to give a measurement with improved
accuracy. Next, the combined measurements are compared with the
first measurements 405. Using this comparison, a normalization
factor is determined 407 and applied 409 to the first measurements
to give a normalized measurement. The normalized measurements will
be more accurate than the first measurements. The normalization
factor may be additive or multiplicative, depending upon the type
of measurements being used. Optionally, the normalized measurements
may be combined with the XLS measurements using eq. (1).
[0040] In a second, preferred embodiment of the invention, a
sequence of steps similar to that outlined in FIG. 3 is carried out
with one difference: the first set of measurements include both the
SS and LS measurements. In this manner, a more precise and more
accurate measurement with reasonably high resolution is
obtained.
[0041] The processing of the data may be accomplished using a
processor that may be located downhole or at an uphole location.
Once the measurement accuracy and precision have been improved
using the methods described above, the parameter of interest may be
obtained using well known prior art techniques. As would be known
to those versed in the art, parameters of interest that may be
determined by nuclear logging tools include a density and a
porosity of the earth formation.
[0042] The logging instrument as described above is suitable for
use on a wireline or may be conveyed into the borehole on a
measurement while drilling device using a drilling tubular such as
a drillstring or coiled tubing. When a drilling tubular is used,
the measurement apparatus is usually part of a bottom hole drilling
assembly. Such conveyance devices are known in the art and are not
discussed further here.
[0043] The present invention has been described with reference to a
nuclear logging instrument. However, the method of the present
invention may also be used with other types of logging instruments,
including an acoustic logging instrument. In an acoustic logging
instrument, signals generated from an acoustic source propagate
through an earth formation and are detected at a plurality of
spaced apart detectors. Dur to the passage through a dispersive
earth formation, the signals suffer degradation at increased
source-receiver distances.
[0044] Additionally, the method of the present invention may also
be used when, for example, the first and second detectors are at
the same distance from the source. However, if the second detector
is sampled more frequently than the first detector, then the second
detector will be less precise than and as accurate as the first
detector.
[0045] 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 such
variations within the scope and spirit of the appended claims be
embraced by the foregoing disclosure.
* * * * *