U.S. patent application number 11/841527 was filed with the patent office on 2008-02-28 for early kick detection in an oil and gas well.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. Invention is credited to Roland E. Chemali, Rocco DiFoggio, Volker Krueger.
Application Number | 20080047337 11/841527 |
Document ID | / |
Family ID | 39092802 |
Filed Date | 2008-02-28 |
United States Patent
Application |
20080047337 |
Kind Code |
A1 |
Chemali; Roland E. ; et
al. |
February 28, 2008 |
Early Kick Detection in an Oil and Gas Well
Abstract
An acoustic transducer on a downhole tool sends an acoustic wave
through a sensor plate in contact with drilling fluid. Vibrations
of the sensor plate are indicative of the impedance of the borehole
plate that may be associated with gas influx. A processor analyzes
the vibrations and uses an estimated Q of the vibrations to
determine gas influx. It is emphasized that this abstract is
provided to comply with the rules requiring an abstract which will
allow a searcher or other reader to quickly ascertain the subject
matter of the technical disclosure. It is submitted with the
understanding that it will not be used to interpret or limit the
scope or meaning of the claims. 37 CFR 1.72(b).
Inventors: |
Chemali; Roland E.; (Humble,
TX) ; Krueger; Volker; (Celle, DE) ; DiFoggio;
Rocco; (Houston, TX) |
Correspondence
Address: |
MADAN, MOSSMAN & SRIRAM, P.C.
2603 AUGUSTA DRIVE, SUITE 700
HOUSTON
TX
77057-5662
US
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
39092802 |
Appl. No.: |
11/841527 |
Filed: |
August 20, 2007 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
60839602 |
Aug 23, 2006 |
|
|
|
Current U.S.
Class: |
73/152.19 |
Current CPC
Class: |
G01N 2291/02818
20130101; G01N 29/024 20130101; E21B 47/107 20200501; G01N 29/028
20130101 |
Class at
Publication: |
73/152.19 |
International
Class: |
E21B 47/12 20060101
E21B047/12 |
Claims
1. An apparatus for detection of gas influx in a borehole fluid
during drilling operations, the apparatus comprising: (a) a
bottomhole assembly (BHA) configured to be conveyed in the
borehole; (b) at least one transducer assembly on the BHA
including: (A) a sensor plate in contact with the borehole fluid,
and (B) a cavity disposed between a transducer and the sensor
plate, the transducer configured to generate acoustic vibrations in
the sensor plate; and (c) a processor configured: (C) to estimate
from a signal indicative of the acoustic vibrations an impedance of
the borehole fluid, and (D) to use the estimated fluid impedance to
provide an indication of the gas influx.
2. The apparatus of claim 1 wherein the cavity includes a fluid
having a known density and compressional velocity.
3. The apparatus of claim 1 wherein the signal indicative of the
acoustic vibrations is provided by at least one of: (i) the
transducer, and (ii) a receiver.
4. The apparatus of claim 1 wherein the sensor plate has an
acoustic impedance selected to match an expected impedance of the
borehole fluid.
5. The apparatus of claim 1 wherein the processor is configured to
estimate the impedance of the borehole fluid by determining a
quality factor (Q) of the acoustic vibrations.
6. The apparatus of claim 1 wherein the processor is configured to
provide the indication of gas influx using a table lookup.
7. The apparatus of claim 1 further comprising a device configured
to measure a P-wave velocity in the borehole fluid and wherein the
processor is configured to provide the indication of gas influx
using a density derived from the estimated fluid impedance and the
measured P-wave velocity.
8. The apparatus of claim 1 wherein the sensor plate is made of a
material selected from: (i) a polyamide, (ii) a polymethylpentene,
(iii) pyrolitic graphite, (iv) titanium, and (v) aluminum.
9. The apparatus of claim 1 further comprising an absorptive
backing on a back side of the transducer having an impedance
substantially equal to that of the transducer.
10. The apparatus of claim 1 wherein the at least one transducer
assembly further comprises a plurality of transducer assemblies in
electrical communication.
11. The apparatus of claim 1 wherein the transducer is configured
to provide the indication of gas influx by providing an alarm
signal when the estimated fluid impedance changes by more than a
specified threshold value relative to the estimated fluid impedance
in an earlier interval.
12. A method of detecting gas influx in a borehole fluid during
drilling operations, the method comprising: (a) conveying a
bottomhole assembly (BHA) including at least one transducer
assembly into the borehole; (b) using a transducer on a first side
of a cavity in the transducer assembly to generate acoustic
vibrations in a sensor plate on a second side of the cavity, the
sensor plate being in contact with the borehole fluid; (c)
estimating from a signal indicative of the acoustic vibrations an
impedance of the borehole fluid, and (d) using the estimated fluid
impedance to provide an indication of the gas influx.
13. The method of claim 12 further comprising having a fluid having
with a known density and a known compressional velocity in the
cavity.
14. The method of claim 12 further comprising providing the signal
indicative of the acoustic vibrations using at least one of: (i)
the transducer, and (ii) a receiver.
15. The method of claim 12 further comprising selecting a material
for the sensor plate that has an acoustic impedance which matches
an expected impedance of the borehole fluid.
16. The method of claim 12 wherein estimating the impedance of the
borehole fluid further comprises determining a quality factor (Q)
of the acoustic vibrations.
17. The method of claim 12 wherein the providing the indication of
gas influx further comprises using a table lookup.
18. The method of claim 12 further comprising measuring a P-wave
velocity in the borehole fluid and wherein the providing the
indication of gas influx further comprises using a density derived
from the estimated fluid impedance and the measured P-wave
velocity.
19. The method of claim 12 further comprising selecting a material
for the sensor plate from: (i) a polyamide, (ii) a
polymethylpentene, (iii) pyrolitic graphite, (iv) titanium, and (v)
aluminum.
20. The method of claim 12 further comprising providing an
absorptive backing on a back side of the transducer to reduce
reflections therefrom.
21. The method of claim 12 further comprising using, for the at
least one transducer assembly, a plurality of transducer assemblies
in electrical communication.
22. The method of claim 12 wherein providing the indication of gas
influx further comprises providing an alarm signal when the
estimated fluid impedance changes by more than a specified
threshold value relative to the estimated fluid impedance in an
earlier interval.
23. A computer readable medium for use with an apparatus for
detection of gas influx in a borehole fluid during drilling
operations, the apparatus comprising: (a) a bottomhole assembly
(BHA) configured to be conveyed in the borehole; (b) at least one
transducer assembly on the BHA including: (A) a sensor plate in
contact with the borehole fluid, and (B) a cavity disposed between
a transducer and the sensor plate, the transducer configured to
generate acoustic vibrations in the sensor plate; the medium
comprising instructions that enable a processor to: (c) estimate
from a signal indicative of the acoustic vibrations an impedance of
the borehole fluid, and (d) use the estimated fluid impedance to
provide an indication of the gas influx.
24. The computer readable medium of claim 23 further comprising at
least one of: (i) a ROM, (ii) an EPROM, (iii) an EAROM, (iv) a
flash memory, and (v) an optical disk.
Description
CROSS-REFERENCES TO RELATED APPLICATIONS This application claims
priority from U.S. Provisional Patent Application Ser. No.
60/839,602 filed on Aug. 23, 2006.
BACKGROUND OF THE DISCLOSURE
[0001] 1. Field of the Disclosure
[0002] This disclosure relates generally to oil and gas well
logging tools. More particularly, this disclosure relates to tools
and methods for identifying the influx of gas into the borehole in
real-time during drilling operations.
[0003] 2. Description of the Related Art
[0004] Exploration for hydrocarbons commonly includes using a
bottomhole assembly including a drill-bit for drilling a borehole
in an earth formation. Drilling fluid or "mud" used in the drilling
may vary in density or "mud weight" for a number of reasons. Such
variations can result from changes in the quantity and density of
cuttings (particles of formation); changes in the "mud program" at
the surface, changes in temperature, etc. Variations in mud density
also occur when gas or liquid enter the borehole from the
formation. Such influx of formation fluids may likely be the result
of formation overpressures or abnormally high pressures.
[0005] Pressure detection concepts are especially important in
drilling. Not only does the drilling rate decrease with a high
overbalance of mud pressure versus formation pressure, but also
lost circulation and differential pressure sticking of the drill
pipe can readily occur. More importantly, an underbalance of mud
pressure versus formation pressure can cause a pressure "kick." A
well may kick without forewarning. Balanced drilling techniques
often require only a fine margin between effective pressure control
and a threatened blowout. Additionally, there are situations where
underbalance is maintained to avoid formation damage so that it is
important to detect inflow of formation liquids into the
borehole.
[0006] Some prior art techniques for detecting abnormal formation
pressure are based on measurement of drilling parameters such as
drilling rate, torque and drag; drilling mud parameters such as mud
gas cuttings, flow line mud weight, pressure kicks, flow line
temperature, pit level and pit volume, mud flow rate; shale cutting
parameters such as bulk density, shale factor, volume and size of
cuttings. All of these suffer from the drawback that the
measurements are not available in real-time as they must wait for
the bottom hole fluid to reach the surface.
[0007] Other prior art methods for identifying possible kicks rely
on density measurements of the borehole fluid. See, for example,
U.S. Pat. No. 4,492,865 to Murphy et al, U.S. Pat. No. 4,412,130 to
Winters, U.S. Pat. No. 6,648,083 to Evans et al., and U.S. Pat. No.
6,768,106 to Gzara et al. A drawback of methods that make density
measurements is that gas must be present in sufficient quantities
to affect the density of the mud, so that dissolved gas that may be
a precursor to a gas kick would not register with conventional
density measuring devices. In addition, the density measurements
made by the prior art devices are responsive to varying degrees to
the density of the formation. They also require the use of a
radioactive source--a safety hazard during drilling operations.
[0008] There is a need for a technique to measure the properties of
the borehole fluid downhole with a single tool in order to detect
kicks and inflow of formation liquids. The present disclosure
satisfies this need.
SUMMARY OF THE DISCLOSURE
[0009] One embodiment of the disclosure is an apparatus for
detection of gas influx in a borehole fluid during drilling
operations. The apparatus includes a bottomhole assembly (BHA)
configured to be conveyed in a borehole. The BHA includes at least
one transducer assembly which has a sensor plate in contact with
the borehole fluid and a cavity disposed between a transducer and
the sensor plate. The transducer is configured to generate acoustic
vibrations in the sensor plate. The apparatus includes a processor
configured to estimate from a signal indicative of the acoustic
vibrations an impedance of the borehole fluid, and to use the
estimated fluid impedance to provide an indication of the gas
influx. The cavity may include a fluid having a known density and
compressional velocity. The signal indicative of the acoustic
vibrations may be provided by the transducer and/or a receiver. A
sensor plate may have an acoustic impedance selected to match an
expected impedance of the borehole fluid. The processor may be
configured to estimate the impedance of the borehole fluid by
determining a quality factor of the acoustic vibrations. The
processor may be configured to provide the indication of gas influx
using a table lookup. The apparatus may further include a device
configured to measure a P-wave velocity in the borehole fluid, and
wherein the processor may be configured to provide the indication
of gas influx using a density derived from the estimated fluid
impedance and the measured P-wave velocity. The sensor plate may be
made of a material selected from a polyamide, a polymethylpentene,
pyrolitic graphite, titanium, and/or aluminum. The at least one
transducer assembly may include a plurality of transducer
assemblies in electrical communication.
[0010] One embodiment of the present disclosure is a method of
detecting a gas influx from the formation during drilling of a
borehole. The method includes conveying a BHA including at least
one transducer assembly into the borehole. A transducer on a first
side of the cavity in the transducer assembly is used to generate
acoustic vibrations in a sensor plate on a second side of the
cavity, the sensor plate being in contact with the borehole fluid.
The method further includes estimating from a signal indicative of
the acoustic vibrations an impedance of the borehole fluid, and
using the estimated fluid impedance to provide an indication of the
gas influx. The method may further include having a fluid with a
known density and knowing compressional velocity in the cavity. The
signal indicative of the acoustic vibrations may be provided using
the transducer and/or a receiver. The method may further include
selecting a material for the sensor plate that has an acoustic
impedance which matches an expected impedance of the borehole
fluid. Estimation of the impedance of the borehole fluid may be
done by determining a quality factor of the acoustic vibrations. A
table lookup may be used to provide the indication of gas influx.
The method may further include measuring a P-wave velocity in the
borehole fluid, and providing the indication of gas influx may
further use a density derived from the estimated fluid impedance
and the measured P-wave velocity. The method may further include
electing a material for the sensor plate from a polyamide, a
polymethylpentene, pyrolitic graphite, titanium, and/or aluminum.
The method may further include providing an absorptive backing on a
backside of the transducer to reduce reflections. A plurality of
transducer assemblies in electrical communication may be used.
Providing the indication of gas influx may further include
providing an alarm signal when the estimated fluid impedance
changes by more than a specified threshold value relative to the
estimated fluid impedance in an earlier interval.
[0011] Another embodiment of the disclosure is a computer readable
medium for use with an apparatus for detecting a gas influx from
the formation during drilling of a borehole. The apparatus includes
a bottomhole assembly configured to be conveyed in a borehole, a
transducer assembly on the BHA that includes a sensor plate in
contact with the borehole fluid, and a cavity between a transducer
and the sensor plate, the transducer being configured to generate
acoustic vibrations in the sensor plate. The medium includes
instructions that enable a processor to estimate from a signal
indicative of the acoustic vibrations an impedance of the borehole
fluid, and use the estimated fluid impedance to provide an
indication of the gas influx. The medium may include a ROM, an
EPROM, a flash memory and/or an optical disk
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] The present disclosure is best understood with reference to
the accompanying figures in which like numerals refer to like
elements and in which:
[0013] FIG. 1 (Prior Art) shows a measurement-while-drilling tool
suitable for use with the present disclosure;
[0014] FIG. 2 is a cross sectional view of a measurement sub of the
present disclosure;
[0015] FIG. 3 is a detailed sectional view of the acoustic
transducer in FIG. 2;
[0016] FIGS. 4A and 4B show exemplary signals using the acoustic
transducer of FIG. 2 when the impedance of the borehole fluid is
(a) close to that of the sensor plate, and (b) different from that
of the sensor plate;
[0017] FIG. 5 (prior art) shows modeled bulk moduli of fluid
mixtures as a function of density using a model of Batzle &
Wang as calculated in the thesis of Terra Bulloch; and
[0018] FIG. 6 shows an embodiment of the disclosure in which a
plurality of acoustic transducers are disposed along the drill
collar.
DETAILED DESCRIPTION OF THE DISCLOSURE
[0019] FIG. 1 shows a schematic diagram of a drilling system 10
with a drillstring 20 carrying a drilling assembly 90 (also
referred to as the bottom-hole assembly, or "BHA") conveyed in a
"wellbore" or "borehole" 26 for drilling the wellbore. The drilling
system 10 includes a conventional derrick 11 erected on a floor 12
which supports a rotary table 14 that is rotated by a prime mover
such as an electric motor (not shown) at a desired rotational
speed. The drillstring 20 includes a tubing such as a drill pipe 22
or a coiled-tubing extending downward from the surface into the
borehole 26. The drillstring 20 is pushed into the wellbore 26 when
a drill pipe 22 is used as the tubing. For coiled-tubing
applications, a tubing injector, such as an injector (not shown),
however, is used to move the tubing from a source thereof, such as
a reel (not shown), to the wellbore 26. The drill bit 50 attached
to the end of the drillstring breaks up the geological formations
when it is rotated to drill the borehole 26. If a drill pipe 22 is
used, the drillstring 20 is coupled to a drawworks 30 via a Kelly
joint 21, swivel 28, and line 29 through a pulley 23. During
drilling operations, the drawworks 30 is operated to control the
weight on bit, which is an important parameter that affects the
rate of penetration. The operation of the drawworks is well known
in the art and is thus not described in detail herein.
[0020] During drilling operations, a suitable drilling fluid 31
from a mud pit (source) 32 is circulated under pressure through a
channel in the drillstring 20 by a mud pump 34. The drilling fluid
passes from the mud pump 34 into the drillstring 20 via a desurger
(not shown), fluid line 38 and Kelly joint 21. The drilling fluid
31 is discharged at the borehole bottom 51 through an opening in
the drill bit 50. The drilling fluid 31 circulates uphole through
the annular space 27 between the drillstring 20 and the borehole 26
and returns to the mud pit 32 via a return line 35. The drilling
fluid acts to lubricate the drill bit 50 and to carry borehole
cutting or chips away from the drill bit 50. A sensor S.sub.1
typically placed in the line 38 provides information about the
fluid flow rate. A surface torque sensor S.sub.2 and a sensor
S.sub.3 associated with the drillstring 20 respectively provide
information about the torque and rotational speed of the
drillstring. Additionally, a sensor (not shown) associated with
line 29 is used to provide the hook load of the drillstring 20.
[0021] In one embodiment of the disclosure, the drill bit 50 is
rotated by only rotating the drill pipe 22. In another embodiment
of the disclosure, a downhole motor 55 (mud motor) is disposed in
the drilling assembly 90 to rotate the drill bit 50 and the drill
pipe 22 is rotated usually to supplement the rotational power, if
required, and to effect changes in the drilling direction.
[0022] In an exemplary embodiment of FIG. 1, the mud motor 55 is
coupled to the drill bit 50 via a drive shaft (not shown) disposed
in a bearing assembly 57. The mud motor rotates the drill bit 50
when the drilling fluid 31 passes through the mud motor 55 under
pressure. The bearing assembly 57 supports the radial and axial
forces of the drill bit. A stabilizer 58 coupled to the bearing
assembly 57 acts as a centralizer for the lowermost portion of the
mud motor assembly.
[0023] In one embodiment of the disclosure, a drilling sensor
module 59 is placed near the drill bit 50. The drilling sensor
module contains sensors, circuitry and processing software and
algorithms relating to the dynamic drilling parameters. Such
parameters typically include bit bounce, stick-slip of the drilling
assembly, backward rotation, torque, shocks, borehole and annulus
pressure, acceleration measurements and other measurements of the
drill bit condition. A suitable telemetry or communication sub 72
using, for example, two-way telemetry, is also provided as
illustrated in the drilling assembly 90. The drilling sensor module
processes the sensor information and transmits it to the surface
control unit 40 via the telemetry system 72.
[0024] The communication sub 72, a power unit 78 and an MWD tool 79
are all connected in tandem with the drillstring 20. Flex subs, for
example, are used in connecting the MWD tool 79 in the drilling
assembly 90. Such subs and tools form the bottom hole drilling
assembly 90 between the drillstring 20 and the drill bit 50. The
drilling assembly 90 makes various measurements including the
pulsed nuclear magnetic resonance measurements while the borehole
26 is being drilled. The communication sub 72 obtains the signals
and measurements and transfers the signals, using two-way
telemetry, for example, to be processed on the surface.
Alternatively, the signals can be processed using a downhole
processor in the drilling assembly 90.
[0025] The surface control unit or processor 40 also receives
signals from other downhole sensors and devices and signals from
sensors S.sub.1-S.sub.3 and other sensors used in the system 10 and
processes such signals according to programmed instructions
provided to the surface control unit 40. The surface control unit
40 displays desired drilling parameters and other information on a
display/monitor 42 utilized by an operator to control the drilling
operations. The surface control unit 40 typically includes a
computer or a microprocessor-based processing system, memory for
storing programs or models and data, a recorder for recording data,
and other peripherals. The control unit 40 is typically adapted to
activate alarms 44 when certain unsafe or undesirable operating
conditions occur.
[0026] Turning now to FIG. 2, a cross-section of an acoustic sub
that can be used for determining the formation density is
illustrated. The drill collar is denoted by 103 and the borehole
wall by 101. An acoustic transducer assembly 107 is positioned
inside the drill collar.
[0027] As shown in FIG. 3, the acoustic transducer assembly
includes an fluid-filled cavity 109. An acoustic transducer 111
such as a piezoelectric transducer is positioned at one side of the
cavity 109. On the other side of the cavity 109 is a sensor plate
115. The cavity is filled with a fluid with known density and
compressional wave velocity. The plate 115 has a known thickness,
compressional wave velocity and density.
[0028] As shown in FIG. 3, activation of the transducer generates
acoustic waves in the fluid. Exemplary raypaths resulting from the
excitation are shown in FIG. 3. The ray path 117, for example,
corresponds to an acoustic wave that is reflected from the inner
wall of the sensor plate. The raypath 121 corresponds to an
acoustic wave that is reflected from the outer surface of the
sensor plate while raypath 119 corresponds to a wave that passes
into the borehole fluid in the annulus between the BHA and the
borehole wall. The transducer 111 is provided with an absorptive
backing 113 with an impedance that closely matches that of the
transducer so as to reduce reflections from the back side of the
transducer. In the example shown, a single transducer acts as both
a transmitter and as a receiver, though this is not to be construed
as limitation to the disclosure: separate acoustic transmitters and
receivers may be used.
[0029] The present disclosure relies on the signals recorded by
excitation of the transducer as an indication of gas in the
borehole fluid. Free gas in the borehole fluid has three main
effects on the acoustic properties of the fluid. The first effect
is a reduction in density of the fluid. A more important effect is
the dramatic reduction in the bulk modulus of the fluid (and hence
the acoustic velocity). This is the phenomenon that is the basis
for the so-called "bright spot" effect in hydrocarbon exploration
wherein the presence of gas in a reservoir can produce strong
reflections on seismic data. Basically, in a gas-liquid mixture,
the average compressibility (the reciprocal of bulk modulus which
is linearly related to the square of the acoustic velocity) is
obtained by a weighted average of the compressibilities of the two
fluids. The third effect that may be observed is the attenuation of
the wave that actually propagates into the borehole and may be
reflected by the borehole wall. However, by the time actual gas
bubbles appear in the borehole at depth, it may be on the verge of
a blowout. Accordingly, an objective of the disclosure is to
determine the pressure kicks before gas comes out of solution in
the borehole fluid.
[0030] Invasion of formation fluids into the borehole is usually
the result of the formation pore pressure exceeding the fluid
pressure in the borehole. This may be a harbinger of a blowout and
remedial action is necessary. Due to the difference in the density
and P-wave velocity of the borehole mud and the density and P-wave
velocity of formation fluid, this influx is detectable.
Specifically, the effect of invasion is to lower the bulk modulus
and density of the fluid in the borehole. This translates into a
change in the impedance of the mud.
[0031] FIG. 5 shows an example of a cross-plot of modeled bulk
modulus versus density for a three phase mixture. The example is
from Bulloch (Michigan Technological University M.S. Thesis) using
a model proposed by Batzle et al. The curve 191 is for an oil-water
mixture for different fluid saturations, the curve 193 is for a
three phase mixture of oil, water and gas, and the curve 195 is for
a gas-water mixture. For the present disclosure, the model of
Batzle et al. may be used with appropriate parameters for drilling
fluid, live oil (oil with dissolved gas) and dead oil. This is not
to be construed as a limitation of the present disclosure and other
models for predicting the elastic properties of fluid mixtures may
be used. Han & Batzle shows correlations of velocity and
density to API gravity, Gas-Oil Raio (GOR), Gas gravity and in situ
pressure and temperatures. This is an example of another model that
may be used with the method of the present disclosure. In practice,
the empirical cross-plots may be stored in the form of a table and
a table lookup performed to determine the presence of gas in the
borehole fluid.
[0032] Such a model may also be used for predicting the properties
of a mixture of drilling mud and formation fluid. The net result of
a fluid influx is to change the impedance of the borehole
fluid.
[0033] Those versed in the art and having benefit of the present
disclosure would recognize that if the impedance of the fluid is
matched to that of the plate, then reverberations of the plate
caused by excitation of the transducer will decay very rapidly.
This is shown schematically in FIG. 4A by the decay curve 153 of
the reverberatory signal 151. If, on the other hand, the impedance
of the fluid is greatly different from that of the plate, the
reverberations 161 die out more slowly 163. The relative decay can
be quantified by the Q (or quality factor) of the plate. This is
something that can be readily measured using prior art
techniques.
[0034] Maximum sensitivity is obtained by using a plate whose
acoustic impedance is as close as possible to the fluid impedance
so as to minimize the impedance contrast with the fluid, which
typically ranges from 1500 kRayls for a light drilling fluid to
2300 kRayls for a heavy drilling fluid. The plate must also be
thermally stable, mechanically tough, and chemically resistant.
Among polymers, a polyimide ranging from 2400 to 2920 kRayls or a
poly(etherether-ketone) ranging from 3122 to 3514 kRayls are good
candidates. Another polymer that is a good candidate is
polymethlypentene (tradenamed TPX, which is made by Mitsui) that
has an acoustic impedance of 1840 kRayls. Pyrolytic graphite (6 480
kRayls depending on orientation) from GE Advanced Ceramics is a
good candidate. Among metals, titanium (about 24 000 kRayls) or
aluminum (about 15 800 kRayls) are good candidates. The inside face
of the plate is in contact with oil in a pressure-balanced
enclosure, with known acoustic characteristics. Incoming water oil
or gas is expected to lower the acoustic impedance markedly. The
instrument takes a reading every second and stores it in memory for
2 hours. In one embodiment of the disclosure, if the instrument
observes a change in acoustic impedance of 10% or more during a 2
minute interval from the extrapolated value of the preceding hour
then it sends a high priority alarm and a series of informative
values of the acoustic impedance from say intervals of 20 seconds
preceding the alarm. The use of a 10% change in acoustic impedance
is for exemplary purposes only and other criteria could be used for
sending an alarm.
[0035] Another embodiment of the disclosure is illustrated in FIG.
6. Here, the BHA 205 is provided with a transducer arrangement 209
of the type discussed above and additional transducer assemblies
211, 213, 215, 217, 219 are disposed along the drill collar 221.
These are in electrical communication with each other and with a
processor at the surface using wired-pipe telemetry (though other
telemetry methods may be used). The impedance of the mud is
estimated by determining the Q of the resonant plate. The velocity
of P-waves in the mud may be measured using, for example, the
apparatus described in U.S. patent application Ser. No. 10/298706
of Hassan et al., having the same assignee as the present
disclosure and the contents of which are incorporated herein by
reference. Once the impedance and velocity are known, the density
can be determined. The density may be a better indication of a
potential gas kick than impedance or velocity separately.
[0036] The processing of the data may be accomplished by a downhole
processor. Alternatively, measurements may be stored on a suitable
memory device and processed upon retrieval of the memory device for
detailed analysis. Implicit in the control and processing of the
data is the use of a computer program 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. All of these
media have the capability of storing the data acquired by the
logging tool and of storing the instructions for processing the
data. It would be apparent to those versed in the art that due to
the amount of data being acquired and processed, it is impossible
to do the processing and analysis without use of an electronic
processor or computer.
[0037] While the foregoing disclosure is directed to the specific
embodiments of the disclosure, various modifications will be
apparent to those skilled in the art. It is intended that all such
variations within the scope of the appended claims be embraced by
the foregoing disclosure.
* * * * *