U.S. patent application number 10/140670 was filed with the patent office on 2003-11-13 for method and apparatus for measuring fluid density downhole.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Goodwin, Anthony R.H..
Application Number | 20030209066 10/140670 |
Document ID | / |
Family ID | 29269691 |
Filed Date | 2003-11-13 |
United States Patent
Application |
20030209066 |
Kind Code |
A1 |
Goodwin, Anthony R.H. |
November 13, 2003 |
METHOD AND APPARATUS FOR MEASURING FLUID DENSITY DOWNHOLE
Abstract
Apparatus for determining the density of a fluid downhole
includes apparatus for measuring compressibility of the fluid and
apparatus for determining the speed of sound through the fluid.
According to the methods of the invention, density of the fluid is
calculated based upon the relationship between density,
compressibility, and the speed of sound through the fluid.
Inventors: |
Goodwin, Anthony R.H.;
(Thomaston, CT) |
Correspondence
Address: |
Intellectual Property Law Department
Schlumberger-Doll Research
36 Old Quarry Rd.
Ridgefield
CT
06877
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Ridgefield
CT
|
Family ID: |
29269691 |
Appl. No.: |
10/140670 |
Filed: |
May 8, 2002 |
Current U.S.
Class: |
73/152.05 ;
73/152.55 |
Current CPC
Class: |
G01N 9/24 20130101; E21B
49/10 20130101 |
Class at
Publication: |
73/152.05 ;
73/152.55 |
International
Class: |
E21B 049/00; E21B
047/08 |
Claims
1. A method for determining the density of hydrocarbon fluid in a
formation, comprising: a) obtaining a sample of the hydrocarbon
fluid from the formation; b) determining the compressibility of the
sample; c) determining the speed of sound through the sample; and
d) calculating the density of the sample from the compressibility
and the speed of sound through the sample.
2. The method according to claim 1, wherein: said determining the
compressibility of the sample is performed with optical fluid
analysis.
3. The method according to claim 1, wherein: said determining the
speed of sound through the sample is performed with a sonic
transceiver.
4. The method according to claim 3, wherein: said determining the
speed of sound through the sample is performed with two sonic
transceivers.
5. The method according to claim 3, wherein: said determining the
speed of sound through the sample is performed with a time of
flight flow meter.
6. The method according to claim 1, wherein: said determining
compressibility includes determining the isentropic compressibility
of the sample, and said calculating density is based on the
relationship .rho.=(u.sup.2.kappa..sub.S).sup.-1 where .rho. is
density, u is the speed of sound through the medium and
.kappa..sub.S is the isentropic compressibility of the sample.
7. The method according to claim 1, wherein: said determining
compressibility includes determining the isothermal compressibility
of the sample, and said calculating density is based on the
relationship .rho.=(u.sup.2.kappa..sub.T).sup.-1 where .rho. is
density, u is the speed of sound through the medium and
.kappa..sub.T is the isothermal compressibility of the sample.
8. An apparatus for determining the density of hydrocarbon fluid in
a formation, comprising: a) fluid conduit which receives a sample
of the hydrocarbon fluid from the formation; b) means for
determining the compressibility of the sample; c) means for
determining the speed of sound through the sample; and d) means for
calculating the density of the sample from the compressibility and
the speed of sound through the sample.
9. The apparatus according to claim 8, wherein: said means for
determining the compressibility of the sample includes an optical
fluid analyzer.
10. The apparatus according to claim 8, wherein: said means for
determining the speed of sound through the sample includes a sonic
transceiver.
11. The apparatus according to claim 10, wherein: said means for
determining the speed of sound through the sample includes two
sonic transceivers.
12. The apparatus according to claim 10, wherein: said means for
determining the speed of sound through the sample includes a time
of flight flow meter.
13. The apparatus according to claim 8, wherein: said means for
determining compressibility includes means for determining the
isentropic compressibility of the sample, and said means for
calculating density utilizes the relationship
.rho.=(u.sup.2.kappa..sub.S).sup.-1 where .rho. is density, u is
the speed of sound through the medium and .kappa..sub.S is the
isentropic compressibility of the sample.
14. The apparatus according to claim 8, wherein: said means for
determining compressibility includes means for determining the
isothermal compressibility of the sample, and said means for
calculating density is based on the relationship
.rho.=(u.sup.2.kappa..sub.T).sup.-1 where .rho. is density, u is
the speed of sound through the medium and .kappa..sub.T is the
isothermal compressibility of the sample.
Description
[0001] This application is related to co-owned U.S. patent
application Ser. No. 09/704,630 filed Nov. 2, 2000, entitled
"Methods and Apparatus for Optically Measuring Fluid
Compressibility Downhole", docket number 20.2754, the complete
disclosure of which is hereby incorporated herein by reference.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates to the analysis of downhole
hydrocarbon fluids. More particularly, the present invention
relates to apparatus and methods for the in situ determination of
the density of hydrocarbon fluids in a geological formation.
[0004] 2. State of the Art
[0005] Naturally occurring hydrocarbon fluids include a wide range
of fluids including dry natural gas, wet gas, condensate, light
oil, black oil, heavy oil, and heavy viscous tar. The physical
properties of these various hydrocarbon fluids, such as density,
viscosity, and compressibility vary considerably. In addition, the
separation of each of the hydrocarbon fluid compositions into
distinctly separate gas, liquid and solid phases, each with its own
physical properties, occurs at certain contours of pressure and
temperature within the formation. This is referred to generally as
the "phase behavior" of the hydrocarbon.
[0006] The economic value of a hydrocarbon reserve, the method of
production, the efficiency of recovery, the design of production
hardware systems, etc., all depend upon the physical properties and
phase behavior of the reservoir hydrocarbon fluid. Hence, it is
important that the fluid properties and phase behavior of the
hydrocarbon be determined accurately following the discovery of the
hydrocarbon reservoir, so that a decision of whether it is
economically viable to develop the reservoir can be made; and if
viable, an appropriate design and plan for the development of the
reservoir can be adopted. With that in mind, those skilled in the
art will appreciate that the ability to conduct an analysis of
formation fluids downhole (in situ) is extremely desirable.
[0007] The assignee of this application has provided a commercially
successful borehole tool, the MDT (a trademark of Schlumberger)
which analyzes formation fluids in situ. The MDT extracts and
analyzes a flow stream of fluid from a formation in a manner
substantially as set forth in co-owned U.S. Pat. Nos. 3,859,851 and
3,780,575 to Urbanosky which are hereby incorporated by reference
herein in their entireties. The OFA (a trademark of Schlumberger),
which is a module of the MDT, determines the identity of the fluids
in the MDT flow stream and quantifies the oil and water based on
other co-owned technology. In particular, co-owned U.S. Pat. No.
4,994,671 to Safinya et al. provides a borehole apparatus which
includes a testing chamber, means for directing a sample of fluid
into the chamber, a light source preferably emitting near infrared
rays and visible light, a spectral detector, a data base means, and
a processing means. Fluids drawn from the formation into the
testing chamber are analyzed by directing the light at the fluids,
detecting the spectrum of the transmitted and/or backscattered
light, and processing the information accordingly in order to
quantify the amount of water and oil in the fluid. As set forth in
co-owned U.S. Pat. No. 5,266,800 to Mullins, by monitoring the
optical absorption spectrum of the fluid samples obtained over
time, a determination can be made as to when a formation oil is
being obtained as opposed to a mud filtrate. Thus, the formation
oil can be properly analyzed and quantified by type.
[0008] The Safinya et al., and Mullins patents represent great
advances in downhole fluid analysis, and are particularly useful in
the analysis of oils and water present in the formation. The issues
of in situ gas quantification and analysis are addressed in the
coowned U.S. Pat. No. 5,167,149 to Mullins et al., U.S. Pat. No.
5,201,220 to Mullins et al., U.S. Pat. No. 5,859,430 to Mullins et
al., U.S. Pat. No. 5,939,717 to Mullins, and in O.C. Mullins et
al., "Effects of high pressure on the optical detection of gas by
index-of-refraction methods", Applied Optics, Vol. 33, No. 34, pp.
7963-7970 (Dec. 1, 1994). In particular, U.S. Pat. No. 5,859,430 to
Mullins et al. discloses a method and apparatus for the downhole
compositional analysis of formation gases which utilizes a flow
diverter and spectrographic analysis. More particularly, the
apparatus includes diverter means for diverting formation gas into
a separate stream, and a separate gas analysis module for analyzing
the formation gas in that stream. The methods and apparatus are
useful in determining what types of gas are present in the
formation fluid. U.S. Pat. No. 5,939,717 to Mullins, on the other
hand, is directed to methods and apparatus for determining in situ
gas-oil ratios (GOR) which are necessary for establishing the size
and type of production facilities required for processing newly
discovered oil.
[0009] Despite these large advances in downhole analysis and
quantification of oil, gas, and water, and gas-oil ratios,
additional information regarding physical properties of the
hydrocarbons such as the hydrocarbon compressibility and density
are desired. Previously incorporated Ser. No. 09/704,630 discloses
methods and apparatus for optically measuring fluid compressibility
downhole. The compressibility of a formation hydrocarbon sample is
determined downhole by using a borehole tool to obtain the sample
downhole, and, at two different pressures, subjecting the sample to
near infrared illumination and conducting spectral absorption
measurement of peaks at and/or around about 6,000 cm.sup.-1 and/or
at and/or about 5,800 cm.sup.-1 (the absorption peaks of methane
and crude oil respectively). The compressibility of the sample is
determined from the change in the peak areas, the change in
pressure, and the measured peak area itself. According to a
preferred embodiment of the invention, the pressure is changed at
least 2000 pounds per square inch (psi), and preferably 4000 or
more psi between measurements.
[0010] Fluid density measurement normally requires the measurement
of the volume occupied by a known mass or the measurement of the
mass of a known volume. Density can be determined in a laboratory
by analyzing a fluid sample taken downhole from the formation.
These measurements are time consuming and suffer from systematic
errors that arise from irreversible changes in the sample upon
transportation from downhole to the laboratory. These measurements
also assume that a representative sample was obtained by the
sampling tool. Although these measurements could be performed at
the well head, thereby reducing the time required for an
identification of low quality samples, such measurements would
still be subject to the issues of sample changes that might occur
while the sample is brought from downhole to the surface.
SUMMARY OF THE INVENTION
[0011] It is therefore an object of the invention to provide
methods and apparatus for measuring fluid density downhole.
[0012] It is also an object of the invention to provide methods and
apparatus for measuring fluid density downhole with a sampling
device during investigative logging.
[0013] It is another object of the invention to provide methods and
apparatus for measuring fluid density downhole with permanent
sensors during production logging.
[0014] It is still another object of the invention to provide
methods and apparatus for measuring fluid density downhole of both
stagnant fluid and flowing fluid.
[0015] In accord with these objects which will be discussed in
detail below, the methods of the present invention include
measuring the compressibility of fluid using the methods and
Optical Fluid Analyzer apparatus of the previously incorporated
co-owned application, measuring the speed of sound in the downhole
fluid, and calculating fluid density based on the compressibility
of the fluid and the speed of sound through the fluid. The
apparatus of the invention includes at least one sound transceiver
and a signal processor. Prior to or after the compressibility of
the fluid is obtained, sound is transmitted through the fluid and
reflected back to the sound transceiver over a known distance. The
signal processor calculates the time delay between the transmission
and reception, and, using the known distance, calculates the speed
of sound through the fluid. The speed of sound is then used with
the compressibility of the fluid to determine density based on a
known physical relationship between isentropic compressibility,
speed of sound and density.
[0016] The sound transceiver is preferably mounted within the
tubing of the Optical Fluid Analyzer so that compressibility and
speed of sound measurements can be made on the same sample.
[0017] According to another embodiment of the apparatus of the
invention, two sound transceivers are used so that the speed of
sound can be measured in two opposite directions through the fluid.
This allows the measurement of the flow rate of flowing fluid as
well as the speed of sound through the fluid. Off the shelf
ultrasonic "time of flight" flow meters may be adapted to suit the
methods of the invention. These devices typically utilize quartz
transducers and generate sound pulses in the range of ten micro
seconds to one millisecond with a frequency in the range of 100 KHz
to one MHz.
[0018] Alternate embodiments of the invention contemplate permanent
or semi-permanent installations of sensors so that the density of
the formation fluids may be measured during production.
[0019] Additional objects and advantages of the invention will
become apparent to those skilled in the art upon reference to the
detailed description taken in conjunction with the provided
figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0020] FIG. 1 is a schematic diagram of a borehole apparatus for
analyzing formation fluids;
[0021] FIG. 2 is a schematic diagram of the optical system of the
preferred near infrared fluid analysis module of FIG. 1 for
determining fluid compressibility and an apparatus according to the
invention for determining speed of sound in fluid;
[0022] FIG. 3 is a schematic diagram of a system for calculating
fluid density according to the invention; and
[0023] FIGS. 4a and 4b are high level flow charts illustrating the
operation of the system of FIG. 3.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0024] The invention is particularly applicable to both production
logging and to borehole investigative logging. For purposes of
brevity, however, the description herein will be primarily directed
to borehole investigative logging, and the terms "borehole" and
"borehole tool" should be read throughout the specification and
claims to encompass a (cased) well and a tool used in a well, as
well as in a borehole. Thus, a borehole tool 10 for testing earth
formations and analyzing the compositions of fluids from the
formation 14 in accord with the invention is seen in FIG. 1. As
illustrated, the tool 10 is suspended in the borehole 12 from the
lower end of a typical multiconductor cable 15 that is spooled in a
usual fashion on a suitable winch (not shown) on the formation
surface. On the surface, the cable 15 is preferably electrically
coupled to an electrical control system 18. The tool 10 includes an
elongated body 19 which encloses the downhole portion of the tool
control system 16. The elongated body 19 also carries a selectively
extendable fluid admitting assembly 20 and a selectively extendable
tool anchoring member 21 which are respectively arranged on
opposite sides of the body. The fluid admitting assembly 20 is
equipped for selectively sealing off or isolating selected portions
of the wall of borehole 12 such that pressure or fluid
communication with the adjacent earth formation is established.
Also included with tool 10 are a fluid analysis module 25 through
which the obtained fluid flows. The fluid may thereafter be
expelled through a port (not shown) or it may be sent to one or
more fluid collecting chambers 22 and 23 which may receive and
retain the fluids obtained from the formation. Control of the fluid
admitting assembly, the fluid analysis section, and the flow path
to the collecting chambers is maintained by the electrical control
systems 16 and 18.
[0025] Additional details of methods and apparatus for obtaining
formation fluid samples may be had by reference to U.S. Pat. No.
3,859,851 to Urbanosky, U.S. Pat. No. 3,813,936 to Urbanosky, and
U.S. Pat. No. 3,811,321 to Urbanosky, which are hereby incorporated
by reference herein. It should be appreciated, however, that it is
not intended that the invention be limited to any particular method
or apparatus for obtaining the formation fluids.
[0026] Turning now to FIG. 2, a preferred fluid analysis module 25
includes a light source 30, a fluid sample tube 32 (coupled to the
fluid admitting assembly 20 of FIG. 1), optical fibers 34, and a
filter spectrograph 39 which includes a fiber coupler or
distributor 36 and an associated detector array 38. The light
source 30 is preferably an incandescent tungsten-halogen lamp which
is kept at or near atmospheric pressure. The light source 30 is
relatively bright throughout the near infrared wavelength region of
1 to 2.5 microns and down to approximately 0.5 microns, and has
acceptable emissions from 0.35 to 0.5 microns. Light rays from the
light source 30 are preferably transported from the source to the
fluid sample by at least part of a fiber optic bundle 34. The fiber
optic bundle 34 is preferably split into various sections. A first
small section 34a goes directly from the light source 30 to the
distributor 36 and is used to sample the light source. A second
section 34b is directed into an optical cell 37 through which the
sample tube 32 runs and is used to illuminate the fluid sample. A
third bundle 34d collects light transmitted or scattered through
the fluid sample and provides the filter spectrograph with the
light for determining the absorption spectrum of the fluid sample.
Optionally, though not necessarily preferred, a fourth fiber optic
bundle 34c collects light substantially backscattered from the
sample for spectrographic analysis. The backscattered spectrum may
be useful if multiple phases are present simultaneously. A three
position solenoid (not shown) is used to select which fiber optic
bundle is directed toward the filter spectrograph 39. Preferably, a
light chopper (not shown) modulates the light directed at the
spectrograph at 500 Hz to avoid low frequency noise in the
detectors.
[0027] As mentioned above, optical bundle 34b directs the light
towards the fluid sample. The fluid sample is obtained from the
formation by the fluid admitting assembly 20 and is sent to the
fluid analysis section 25 in tube 32. The sample tube 32 is
preferably a two by six millimeter rectangular channel which
includes a section 40 with windows made of sapphire. This window
section 40 is located in the optical cell 37 where the light rays
are arranged to illuminate the sample. Sapphire is chosen for the
windows because it is substantially transparent to the spectrum of
the preferred light source and because it is highly resistant to
abrasion. As indicated schematically in FIG. 2, the window areas 40
may be relatively thick compared to the rest of the tube 32 to
withstand high internal pressure. The fiber optic bundles 34b and
34d are preferably not perpendicular to the window areas 40 so as
to avoid specular reflection. The window areas are slightly offset
as shown in FIG. 2 to keep them centered in the path of the
transmitted light. The signals from the detectors are digitized,
multiplexed, and transmitted uphole via the cable 15 to the
processing electronics 18 shown in FIG. 1.
[0028] Further details regarding the methods and apparatus for
optically determining compressibility can be found in the
previously incorporated co-owned application. The methods and
apparatus provide isothermal compressibility.
[0029] According to a presently preferred embodiment of the present
invention, a pair of sound (preferably ultrasonic) transceivers 50,
52 are mounted adjacent the tube 32 either upstream or downstream
of the optical cell 37. The transceivers 50, 52 are controlled by
the uphole electronics 18 via the cable 15 shown in FIG. 1. These
devices typically utilize quartz transducers and generate sound
pulses in the range of ten micro seconds to one millisecond with a
frequency in the range of 100 KHz to one MHz.
[0030] The methods of the invention are based on the relationship
between density .rho., compressibility .kappa., and the speed of
sound u through a fluid. In the absence of dispersion, the density
.rho. of a phase of fixed composition is related to the isentropic
compressibility .kappa..sub.S and the speed of sound u as defined
by Equation (1).
.rho.=(u.sup.2.kappa..sub.S).sup.-1 (1)
[0031] Isentropic means that there is constant entropy S, that the
process is adiabatic (thermally insulated), and that the process is
reversible. The compressibility .kappa..sub.S is defined by
Equation (2) where V is volume and p is pressure.
.kappa..sub.S=-V.sup.-1(.differential.V/.delta.p).sub.S (2)
[0032] An estimate of the plausible error arising from the
difference between isothermal compressibility .kappa..sub.T
(obtained from the optical measurements described above) and
isentropic compressibility .kappa..sub.S (needed to determine
density using Equation (1)) can be obtained from the thermodynamic
relationship between them given by Equation (3) where .alpha. is
the isobaric expansivity, and C.sub.p is the heat capacity at
constant pressure. .kappa..sub.T is defined by Equation (4) and
.alpha. is defined by Equation (5).
.kappa..sub.T-.kappa..sub.S=T.alpha..sup.2V/C.sub.p (3)
k.sub.T=-V.sup.-1(.differential.V/.differential.p).sub.T (4)
.alpha.=-V.sup.-1(.differential.V/.differential.p).sub.T (5)
[0033] In an isolated system of constant energy, volume, and
content, the change in entropy over time is given by the
relationship (6) where t is time.
(.differential.S/.differential.t).sub.U,V,N>0 (6)
[0034] Since .kappa..sub.T, T, .alpha., V, and C.sub.p are all
necessarily positive or zero, it follows that .kappa..sub.T is
never less than .kappa..sub.S.
EXAMPLE
[0035] For n-octane, at a pressure of 50 MPa and a temperature of
350 K, the following values are obtained from the Equations given
above:
[0036] .alpha.=0.00054733 K.sup.-1,
[0037] .kappa..sub.S=0.00099997 MPa.sup.-1,
[0038] .kappa..sub.T=0.0010594 MPa.sup.-1,
[0039] C.sub.p=282.64 J.multidot.mol.sup.-1.multidot.K.sup.-1,
and
[0040] u=1183.9 m.multidot.s.sup.-1.
[0041] Solving Equation (1) using the values u and .kappa..sub.S
given above yields a density .rho.=713.48 Kg.multidot.m.sup.-3. If
the value of .kappa..sub.T is used in Equation (1), rather than the
value of .kappa..sub.S, the calculated density .rho.=673.5
Kg.multidot.m.sup.-3, which is 5.6% lower than the calculated
density using .kappa..sub.S. It is expected that similar upper
bound errors could arise for other hydrocarbons. Thus, even a crude
approximation of .alpha. and C.sub.p will yield relatively accurate
results.
[0042] Turning now to FIG. 3, an exemplary system 100 for
determining density according to the invention is illustrated in
schematic form. The system 100 includes the Optical Fluid Analyzer
102 of the previously incorporated co-owned application. As
illustrated in FIG. 3, the reference numerals to the components of
the OFA 102 are the same as those used in the previously
incorporated co-owned application. These components generally
include optical sensors 38, a valve 115, a pump 135, a pressure
gauge 135 and processing electronics 18a for calculating the
isothermal compressibility .kappa..sub.T. The system 100 also
includes the aforementioned sonic transceivers 50, 52, processing
electronics 18b for calculating the speed of sound u, and
processing electronics 18c for calculating density .rho.. It will
be appreciated that the electronics 18a, 18b, and 18c may be a
single circuit utilizing one or more microprocessor(s), signal
processor(s), and/or application specific integrated circuit(s)
ASIC(s) and/or field programmable gate array(s) FPGA(s).
[0043] Referring now to FIGS. 3 and 4a, the operation of the OFA
102 is as described in the previously incorporated co-owned
application which assumes that the fluid sample is stagnant and
subject to pressurization. It will be appreciated that in the case
of a stagnant sample, only one sonic transceiver and one speed of
sound measurement is needed.
[0044] In FIG. 4a, the valve 115 is opened and a fluid sample is
collected at 202. The valve is closed at 204 and a first
measurement is made at 206. The pump 125 is activated to pressurize
the sample at 208 until a pressure is determined with the pressure
gauge 135. A second measurement is made at 210 at the higher
pressure. The compressibility is then calculated at 212.
[0045] Using the sonic transceivers 50, 52, a sound is transmitted
from one to the other at 214 and the transit time t.sub.1 of the
sound is recorded at 216. If desired, a sound may also be
transmitted from the second transceiver to the first at 218 with a
second transit time t.sub.2 being recorded at 220. The transit
time(s), taken in conjunction with the known distance between the
transceivers yield a velocity at 222.
[0046] Having calculated the compressibility of the sample at 212
and the speed of sound through the sample at 222, the density is
then calculated at 224 and the process ends at 226. Those skilled
in the art will appreciate that the density calculation can be
performed using the isothermal compressibility obtained at 212 or,
for a more accurate calculation, the isentropic compressibility can
be obtained from the isothermal compressibility using estimates of
C.sub.p and .alpha. as described above. It will also be appreciated
that the operation of the OFA at 202 through 212 may be performed
after the calculation of the speed of sound at 222 rather than
before the operation of the first transceiver at 214. It will also
be understood that, depending on the apparatus used, it is possible
to perform the optical and sonic operations simultaneously.
[0047] Turning now to FIG. 4b, according to an alternate
embodiment, the sonic measurements are made on flowing fluid before
the optical measurements are made on stagnant fluid. Accordingly,
after the valve is opened at 302, two sonic measurements are made
on the flowing fluid before the valve is closed at 304. In
particular, as seen in FIG. 4b, sound is transmitted at 314 from
the first transceiver to the second transceiver and the first time
is recorded at 316. Sound is then sent from the second transceiver
to the first transceiver at 318 and the second time is recorded at
320. The first time and the second time, taken in conjunction with
the known distance between the transceivers yield two velocities.
Those skilled in the art will appreciate that one of the velocities
represents the speed of sound through the fluid plus the velocity
of the fluid and the other represents the speed of sound through
the fluid minus the velocity of the fluid. Thus, the sum of the two
velocities will equal two times the speed of sound through the
fluid and the difference between the velocities will equal two
times the flow rate of the fluid. Thus, at 322 is possible to
calculate both the speed of sound through the fluid and the flow
rate of the sample.
[0048] After the valve is closed at 304, the OFA is operated at
306-312 in the manner described in the previously incorporated
co-owned application to determine compressibility at 312. Having
calculated the speed of sound through the sample at 322 and the
compressibility of the sample at 312, the density is then
calculated at 324 using Equation (1).
[0049] There have been described and illustrated herein several
embodiments of methods and apparatus for determining the density of
a downhole fluid. While particular embodiments of the invention
have been described, it is not intended that the invention be
limited thereto, as it is intended that the invention be as broad
in scope as the art will allow and that the specification be read
likewise. Thus, while specific apparatus have been disclosed, it
will be appreciated that other apparatus for determining
compressibility and speed of sound through the fluid could be
utilized. Also, while two sonic transceivers have been shown, it
will be recalled that in the case of a stagnant sample a single
transceiver is sufficient. It will therefore be appreciated by
those skilled in the art that yet other modifications could be made
to the provided invention without deviating from its spirit and
scope as so claimed.
* * * * *