Note: Descriptions are shown in the official language in which they were submitted.
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FORMATION FLUID EVALUATION
[0001]
[0002]
BACKGROUND OF THE DISCLOSURE
[0003] Tools exist for acquiring representative samples of reservoir
hydrocarbon, such
as the Modular Dynamics TesterTm of Schlumberger. These systems comprise
probes,
packers, and/or other means for connecting the internal mechanism of the tool
with the
formation. These systems also comprise pumps to extract reservoir fluid, fluid
analysis
devices to evaluate physical properties of the fluid including the quantity of
mud filtrate, and
fluid storage vessels to retrieve the fluid to surface. When these components
are operated,
they permit the acquisition of a sample representative of reservoir fluid with
minimal
contamination of filtrate that has invaded the reservoir pores close to the
bore-hole wall.
These fluid sampling systems contain tubulars that interconnect the
probe/packer through
often tortuous routes and valves containing restrictions. Ultimately, when the
fluid analyzer
indicates the mud contamination is sufficiently low, a sample is retrieved
into bottles. Fluid
sampling systems equipped with probes have been
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used with success in conventional oil and gas reservoirs, while dual packer
systems have been
used, for example, in formations of low-permeability.
[0004] Pumps within the sampling tools can operate with pressure
differences between the
formation and internal mechanisms of the tool of up to 7.5 kpsi. When the
internal tool tubulars
are filled with fluid of viscosity on the order of 1 cP at flow-rates of the
order of 10 cm3/s, the
pressure drop that arises is negligible compared to 7.5 kpsi. In addition,
conventional oil is
typically located in consolidated formations, such that the formation neither
collapses nor enters
as solid granules into the sampling tool.
[0005] The density of a single phase fluid is one of the fundamental
physical parameters
required to describe fluid flow within the reservoir or borehole, as well as
to determine both the
properties of the surface facilities and the economic value of the fluid.
Density is also required
to provide the volume translation factor for cubic equations of state that are
then often used for
reservoir simulation. A measure of the single phase fluid density within the
sampling tool
provides a real-time in-situ determination of bore-hole fluid contamination,
as well as economic
value. Immiscible fluids are required, or a separator may be needed to provide
the single phase
fluid. Measurements with emulsions may be performed if the volume of each co-
mingled phase
is known before the density of the oil is extracted, and this can be achieved
with, for example,
coincidence gamma-ray attenuation measurements with a micro Curie source. For
most
applications, an expanded uncertainty in density of 0.01 p is sufficient.
BRIEF DESCRIPTION OF THE DRAWINGS
[0006] The present disclosure is best understood from the following
detailed description
when read with the accompanying figures. It is emphasized that, in accordance
with the standard
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practice in the industry, various features are not drawn to scale. In fact,
the dimensions of the
various features may be arbitrarily increased or reduced for clarity of
discussion.
[0007] Figs. 1A and 1B are schematic views of while-drilling apparatus
according to one or
more aspects of the present disclosure.
[0008] Fig. 2 is a schematic view of wireline apparatus according to one or
more aspects of
the present disclosure.
[0009] Fig. 3 is a perspective view of sensor apparatus according to one or
more aspects of
the present disclosure.
[0010] Figs. 4A-4D are various view of the apparatus shown in Fig. 3.
[0011] Figs. 5-8 are schematic views of apparatus according to one or more
aspects of the
present disclosure.
[0012] Fig. 9 is a flow-chart diagram of at least a portion of a method
according to one or
more aspects of the present disclosure.
[0013] Fig. 10 is a schematic view of apparatus according to one or more
aspects of the
present disclosure.
[0014] Fig. 11 is a flow-chart diagram of at least a portion of a method
according to one or
more aspects of the present disclosure.
[0015] Fig. 12 is a flow-chart diagram of at least a portion of a method
according to one or
more aspects of the present disclosure.
DETAILED DESCRIPTION
[0016] It is to be understood that the following disclosure provides many
different
embodiments, or examples, for implementing different features of various
embodiments.
Specific examples of components and arrangements are described below to
simplify the present
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disclosure. These are, of course, merely examples and are not intended to be
limiting. In
addition, the present disclosure may repeat reference numerals and/or letters
in the various
examples. This repetition is for the purpose of simplicity and clarity and
does not in itself dictate
a relationship between the various embodiments and/or configurations
discussed. Moreover, the
formation of a first feature over or on a second feature in the description
that follows may include
embodiments in which the first and second features are formed in direct
contact, and may also
include embodiments in which additional features may be formed interposing the
first and
second features, such that the first and second features may not be in direct
contact.
[0016a] Some embodiments disclosed herein relate to a downhole logging
tool,
comprising: a reservoir containing a first fluid having a first density that
is known; a first
densimeter configured to receive the first fluid from the reservoir and output
a first resonance
frequency related to the first density; a second densimeter configured to
receive a second fluid
from a downhole formation proximate the logging tool and output a second
resonance
frequency related to a second density of the second fluid that is unknown; a
first heater
adjacent or proximate to the first densimeter or the second densimeter and
configured to
adjust a temperature of the first densimeter or the second densimeter such
that the temperature
of the first densimeter and the second densimeter are substantially the same;
and an analyzer
configured to determine downhole the second density based on the known first
density, the
first resonance frequency received from the first densimeter, and the second
resonance
frequency received from the second densimeter.
[0016b] Some embodiments disclosed herein relate to a method of in-
situ formation
fluid evaluation, comprising: measuring a first resonance frequency of a first
fluid using a first
densimeter downhole, wherein a first density of the first fluid is known;
measuring a second
resonance frequency of a second fluid using a second densimeter downhole,
wherein the
second fluid is a formation fluid received by the second densimeter downhole,
and wherein a
second density of the second fluid is unknown; determining a viscosity of the
second fluid;
determining the second density of the second fluid using the first and second
resonance
frequencies and the known first density; and iteratively determining a
viscosity and the second
density of the second fluid until a variation of the determined viscosity and
the second density
is less than an estimated uncertainty.
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100171 Fig. lA is a wellsite system in which one or more aspects of
the present
disclosure can be employed. The wellsite can be onshore or offshore. In this
exemplary
system, a borehole 11 is formed in subsurface formations by rotary drilling in
a manner that is
well known. Embodiments of the present disclosure may also use directional
drilling, as will
be described hereinafter.
[0018] A drill string 12 is suspended within the borehole 11 and has
a bottom hole
assembly 100 which includes a drill bit 105 at its lower end. The surface
system includes
platform and derrick assembly 10 positioned over the borehole 11, the assembly
10 including
a rotary table 16, kelly 17, hook 18 and rotary swivel 19. The drill string 12
is rotated by the
rotary table 16, energized by means not shown, which engages the kelly 17 at
the upper end of
the drill string. The drill string 12 is suspended from a hook 18, attached to
a traveling block
(also not shown), through the kelly 17 and a rotary swivel 19 which permits
rotation of the
drill string relative to the hook. As is well known, a top drive system could
alternatively be
used.
[0019] In the example of this embodiment, the surface system further
includes drilling
fluid or mud 26 stored in a pit 27 formed at the well site. A pump 29 delivers
the drilling
fluid 26 to the interior of the drill string 12 via a port in the swivel 19,
causing the drilling
fluid to flow
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downwardly through the drill string 12 as indicated by the directional arrow
8. The drilling fluid
exits the drill string 12 via ports in the drill bit 105, and then circulates
upwardly through the
annulus region between the outside of the drill string and the wall of the
borehole, as indicated
by the directional arrows 9. In this well known manner, the drilling fluid
lubricates the drill bit
105 and carries formation cuttings up to the surface as it is returned to the
pit 27 for
recirculation.
[0020] The bottom hole assembly 100 of the illustrated embodiment comprises
a logging-
while-drilling (LWD) module 120, a measuring-while-drilling (MWD) module 130,
a roto-
steerable system and motor, and drill bit 105.
[0021] The LWD module 120 is housed in a special type of drill collar, as
is known in the
art, and can contain one or a plurality of known types of logging tools. It
will also be understood
that more than one LWD and/or MWD module can be employed, e.g. as represented
at 120A.
(References, throughout, to a module at the position of 120 can alternatively
mean a module at
the position of 120A as well.) The LWD module includes capabilities for
measuring, processing,
and storing information, as well as for communicating with the surface
equipment. In the
present embodiment, the LWD module 120 includes a fluid sampling device.
[0022] The MWD module 130 is also housed in a special type of drill collar,
as is known in
the art, and can contain one or more devices for measuring characteristics of
the drill string and
drill bit. The MWD tool further includes an apparatus (not shown) for
generating electrical
power to the downhole system. This may typically include a mud turbine
generator powered by
the flow of the drilling fluid, it being understood that other power and/or
battery systems may be
employed. In the present embodiment, the MWD module includes one or more of
the following
types of measuring devices: a weight-on-bit measuring device, a torque
measuring device, a
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vibration measuring device, a shock measuring device, a stick slip measuring
device, a
direction measuring device, and an inclination measuring device.
[0023] Fig. 1B is a simplified diagram of a sampling-while-drilling
logging device of
a type described in U.S. Patent 7,114,562, utilized as the LWD tool 120 or
part of an LWD
tool suite 120A. The LWD tool 120 is provided with a probe 6 for establishing
fluid
communication with the formation and drawing the fluid 21 into the tool, as
indicated by the
arrows. The probe may be positioned in a stabilizer blade 23 of the LWD tool
and extended
therefrom to engage the borehole wall. The stabilizer blade 23 comprises one
or more blades
that are in contact with the borehole wall. Fluid drawn into the downhole tool
using the probe
26 may be measured to determine, for example, pretest and/or pressure
parameters.
Additionally, the LWD tool 120 may be provided with devices, such as sample
chambers, for
collecting fluid samples for retrieval at the surface. Backup pistons 81 may
also be provided
to assist in applying force to push the drilling tool and/or probe against the
borehole wall. The
LWD tool 120 also comprises means for measuring fluid density in-situ, as
described below.
[0024] Referring to Fig. 2, shown is an example wireline tool 200 that may
be another
environment in which aspects of the present disclosure may be implemented. The
example
wireline tool 200 is suspended in a wellbore 202 from the lower end of a
multiconductor cable
204 that is spooled on a winch (not shown) at the Earth's surface. At the
surface, the cable
204 is communicatively coupled to an electronics and processing system 206.
[0025] The example wireline tool 200 includes an elongated body 208 that
includes a
formation tester 214 having a selectively extendable probe assembly 216 and a
selectively
extendable tool anchoring member 218 that are arranged on opposite sides of
the elongated
body 208. The extendable probe assembly 216 is configured to selectively seal
off or isolate
selected portions of the wall of the wellbore 202 to fluidly couple to the
adjacent formation F
and/or to
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draw fluid samples from the formation F. Accordingly, the extendable probe
assembly 216 may
be provided with a probe having an embedded plate. The formation fluid may be
expelled
through a port (not shown) or it may be sent to one or more fluid collecting
chambers 226 and
228. In the illustrated example, the electronics and processing system 206
and/or a downhole
control system are configured to control the extendable probe assembly 216
and/or the drawing
of a fluid sample from the formation F.
[0026] Additional components (e.g., 210) may also be included in the tool
200. For
example, the tool 200 also may also comprise means for measuring fluid density
in-situ, as
described below.
[0027] There are many methods that can be used to measure fluid density in
a laboratory,
including methods of determining fluid densities as well as absolute density
standards. Of these,
the methods that appear most appropriate for down-hole applications are those
that do not rely on
the knowledge of the orientation of the transducer with respect to the local
gravitational field.
Some of these methods are based on determining the resonance frequency of a
vibrating object.
There are many geometrical arrangements that have been reported for
oscillating object
densimeters, with the fluid contacting either the outer or inner surface of a
(usually) metallic
object. When the fluid is in contact with the outer surface, the measurement
is usually
considered intrusive when operated at elevated pressure, but when the fluid is
inside a tube, the
measurement is usually considered non-invasive. Once the particular device has
been selected, a
working equation must be developed to relate the measured quantity (e.g.,
frequency) to density,
as well as to provide a measurement with an expanded uncertainty that is fit
for purpose (k = 2 or
95 % confidence interval).
[0028] In view of the tubulars within a formation pressure tester, a good
measure of density
may be obtained through the use of a vibrating U-tube densimeter. The
vibrating U-tubes offer
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advantages for wire-line (as well as other tool conveyance methods and
LWD/MWD) in that
they can be of low mass and can be well suited to sustaining mechanical shock,
rapid changes in
local acceleration, and the resultant application of large forces. Indeed, as
the internal diameter
of the tube decreases, so does the outer diameter, while still maintaining the
ability to sustain a
pressure difference across the tube from within. The type of material used to
construct the tube
and its elastic properties determine the absolute value of the pressure
difference sustainable by a
tube wall. The sensitivity of the measured frequency to the density of the
fluid is proportional to
the ratio of the mass of the tube to that of the fluid contained within, thus,
it can be important to
minimize the mass of the tube relative to that of the fluid while still
maintaining mechanical
integrity.
[0029] The U-tube may be either an existing tubular of the formation
pressure tester or
another internal side-branch or analysis system. Thus, the inner diameter and
sample volume can
vary, and affords another advantage of the U-tube densimeter. For example, a
tube having an
internal diameter of 1.2 mm, a length of 0.5 m, and bent into a U shape, has
an internal volume
of about 0.5x10-6 m3, which falls into a category of devices known as micro-
fluidic. The
bursting pressure may be estimated to be 70 MPa for a tube outer diameter of
1.65 mm. This
possibility means U-tube densimeters can be used in situations where it is
otherwise difficult to
obtain large fluid volumes (e.g., greater than 0.5x10-6 m3) and thus permits
in-situ operation in
the reservoir hitherto impossible owing to the difficulty of obtaining greater
volumes. These
reservoir types include heavy oil, tight gas, and where ubiquitous water forms
emulsions,
because the measurement scheme can also be connected to a filtration of
separation system.
[0030] Fig. 3 is a perspective view of a known vibrating tube densimeter
300 having the
magnetic field of the magnet 305 orientated at about 30 degrees to the plane
of the tube 310 to
preferentially excite both in-plane and out-of-plane resonances of the nearly
doubly degenerate n
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= 3 mode. The U-tube is held in a clamp 315 in an arrangement that ensures the
electrical
resistance between the clamped ends of the tube 310. This permits the
measurement of motional
EMF (electromotive force) generated by the application of an alternating
current (AC), at
frequencies close to that of the tube resonance, in the presence of the
magnetic field (although
other excitation and detection schemes have also been used). The magnetic
field can be obtained
from either permanent magnets or electromagnets, which can be attached
directly to the
oscillating tube with ceramic cement or a mechanical clamp.
[0031] Two vibrating tube devices which eliminate the requirement to use
electromagnets
and any appendages attached to the sensitive element of the densimeter tube
have been reported
in the literature. Eliminating the electromagnets removes the requirement that
the clamp which
holds the tube must have an electrical resistance much greater (about 104 Q)
than the resistance
of the tube over the U-length; the clamp electrically isolates the two ends
and permits
measurement of the motional emf. The first of these is a silicon based micro-
electromechanical
system (ME MS) reported by Enoksson, et al., and the second is a metallic tube
and support
described by Moldover and Chang. The MEMS device, although of the mm scale,
had a
variation of resonance with density offidf7dp -2=10-4 m3=kg-1 and uncertainty
in density of
about 0.01.p. The vibration of this tube was excited electrostatically with an
electrode separated
from the tube by 30 gm with a sine wave of amplitude 100 V AC. The tube motion
was detected
with a laser and a position sensitive photodetector. Although untested beyond
ambient
conditions, presumably this device could operate at elevated temperature with
corrosive fluids
but, owing to the two piece tube construction, would be unable to withstand
elevated internal
pressures without additional pressure compensation.
[0032] The second vibrating tube design, shown in Figs. 4A-D as device 400,
also eliminates
electromagnets and appendages attached to tube of the densimeter, and can
operate at elevated
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temperature. Fig. 4A is a rear view of the instrument showing tube clamps 415
and mica (or
other) insulation 420 without the magnet 405, magnet clamp 425 or U-tube 410.
Fig. 4B is a
front view showing the magnet clamp 425. Fig. 4C is a left side view
illustrating the clamping
bolts 430. Fig. 4D is a right side view of the device as viewed from the
front.
[0033] Measurements of the density of toluene, obtained with a device
similar to that shown
in Fig. 4, at temperatures between 298 K (where the density is about 900 kg-m-
3) and 575 K
(where the density is about 600 kg-m-3) at pressures below 13.8 MPa were
reported. For this
devicejldfidp -8.10-5 m3.kg-1, which is a factor of 3 lower than for
Enoksson's MEMS device.
The root mean square (RMS) deviation of densities obtained from the tube
oscillation from
literature was less than 0.001.p. Over a ten day period and at a temperature
of 300 K, the
resonance frequency of the evacuated tube was stable to better than 0.00025f
Annealing the U-
tube at a temperature above the range of operation resulted in a device with
fractional stability in
the resonance frequency of about 2-10-6 d-1 at a temperature of 575 K
(equivalent to 0.025 m3-kg-
1-d-1), while at lower temperatures the drift rate was less than 10-6 d-1.
This device meets the
requirements for the thermal environment found in the oilfield. Dilation of
the tube with
pressure was determined by calibration with water. Vibrating U-tube
densimeters have also been
used to determine the density of fluids over a wide range of density,
temperature and pressure,
including measurements on aqueous electrolytes solutions.
[0034] For a vibrating tube densimeter having a straight tube clamped at
both ends and filled
with fluid and surrounded by either another fluid or vacuum, and assuming the
fluid within the
tube does not flow and thus the viscosity of the fluid is neglected, and
further assuming that
negligible internal damping exists, a working equation derived from the Navier-
Stokes equations
for a tube within vacuum reduces to:
p = K (T, p) I + L(T, p) (1)
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This is the working equation routinely used for vibrating U-tubes. It is
assumed that it applies
even when the cross section is non-uniform and the tube is curved into a U-
shape.
[0035] An alternative analysis provides an equation of functional form
similar to Eq. 1. That
is, Eq. 1 only applies when the outer surface of the tube is exposed to
vacuum. However, if the
tube is filled with liquid (or fluid at liquid densities), the tube can be
immersed in a gas at a
pressure of about 0.1 MPa. The magnitude of the pressure and temperature
effect can be
estimated for the tube shown in Figs. 4A-D. A pressure difference of 100 MPa
across the tube
wall with p ¨ 0.1 MPa outside gives rise to a 0.3 % increase of internal
volume and thus a
decrease in measured density, while a 200 K temperature increment results in
volume increase of
0.96 % and resulting underestimate of density. Eq. 1 assumes the restoring
forces, which
contribute to the oscillation, are in bending and shear of the tube. However,
Eq. 1 has been
applied successfully to both a curved tube, for which the eigenfrequencies are
not easily
calculated, and a tube of non-uniform cross-section.
[0036] The eigenfrequenciesf, of a vibrating tube are then given by:
r \1/2
711( Y
fn = ____________ 182
2L2 j (2)
where K is the radius of gyration about the axis of the tube, Y is Young's
modulus, pt is the tube's
mass density, and fir, are the eigenvalues: = 1.5056, )32 = 2.4997, and
fir,>2 17 + 0.5.
[0037] The sensitivity of a vibrating U-tube densimeter is, to first order,
determined by the
ratio between the mass of the tube and the fluid within it. Thus, decreasing
the wall thickness by
a factor increases the sensitivity by a factor of the same order. However, the
working pressure
for a tube, which is a fraction of the elastic limit, increases with
increasing wall thickness, with
an upper limit set by the material properties. A tube should be constructed
from a material with
high tensile and yield strengths.
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[0038] Usually, the fluid density is determined from the frequency of the
tube's n = 1 mode
given by Eq. 2. This places an additional constraint on the structure that
holds the U-tube
because it must recoil in response to the tube's motion. The tube resonance
frequency is then
coupled to the support and can give rise to an additional uncertainty in the
measured frequency
arising from the energy loss. Experiments have shown that the inertial effect
is rendered
insignificant when the support is of mass on the order of 1000 times greater
than the tube
because this reduces the effective mode coupling.
[0039] However, the n = 3 mode has several potential advantages over the n
= 1 mode for
small fast response densimeters. For a straight tube, the n = 3 mode is doubly
degenerate. For a
slightly bent tube, the third mode is almost degenerate, with one component
moving in-plane
with lower frequency, and one out-of-plane with higher frequency. For a U-
tube, the frequency
difference between the two modes is on the order of 10 Hz, much larger than
the resonance line
width. For the n = 3 mode, the straight portions of the U-tube bend toward and
away from each
other. To the extent that this motion is antisymmetric, the center of mass
does not move, the
structure supporting the U does not recoil, and the sensitivity of the tube's
resonance frequency
to the support is reduced.
[0040] The location of the magnetic field relative to the tube plane
determines which
components of the mode are detected. At 7r/4 out-of-plane, both modes can be
measured, while
at n- /2 only the in-plane motion can be observed, owing to the presence of a
node. In addition,
the higher frequency reduces the susceptibility of the device to low frequency
environmental
noise, which typically occurs at frequencies below 2 kHz. Other benefits of
operating at higher n
(and frequencies) with high Q resonances are the reduced settling time
required between
frequency changes and data acquisition that occurs when the resonance
frequency of the tube is
determined from measurements of the in-phase and quadrature voltages of the
response at
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discrete frequencies over the resonance: a steady state measurement. At each
step, the
instrument waited about three times 1/(2g), where g, is the half the resonance
line-width at 1/21/2
of the maximum amplitude. The power dissipation in the tube was negligible and
did not cause
self-heating.
[0041] Another source of error arises from the assumptions of no internal
damping and
absence of fluid movement into and out of the tube that were used to obtain
Eq. 1. Past
experiments reported in the literature have shown the error arising from
neglecting viscosity in
the working equations by comparing the results obtained with the vibrating
tube with values
determined by other means, typically a pycnometer. One report considered
fluids with
viscosities in the range of 1 to 103 mPa-s (with an Anton Paar DMA 02C
densimeter). A second
report studied fluids with viscosities between 1 and 40 mPa-s with a glass U-
tube (Anton Paar
model DMA 602), whereas a third study used metallic U-tubes at viscosities
below 4 Pa-s. The
second and third studies determined that the vibrating tube gave values
greater than the
pycnometer and provided empirical expressions as a function of viscosity to
estimate the
correction. Anton Paar recommends that, for a model 512P densimeter, the
correction to density
for fluid viscosity is given by:
Ap= p[-0.5+ 0.45(ij/mPa =s)1/2 =10-4 (3)
and, subtracted from Eq. 1:
p=K(T,p)1 f2 L(T,p)¨ Ap(q) 1 p (4)
[0042] For a vibrating tube filled with fluid of viscosity n 76 mPa-s, Eq.
3 returns 102Ap/p
= 0.034%, while extrapolation of the expression reported in the first study by
a viscosity of about
26 mPa-s gives 102Ap/p = 0.044%, and that of the second study provides 102Ap/p
= 0.048%. The
data in the third study suggest 102Ap/p increases linearly with increasing
viscosity up to a
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viscosity of about 400 mPa-s where the uncertainty is about 0.09%; at higher
viscosities, the
uncertainty in density increases to about 0.1% at a viscosity of 4 Pas.
However, it still remains a
task for theoretical mechanics to explain these observations.
[0043] In view of this deficiency, a calibration is required to accommodate
the above-
described effects as well as those of the clamps, supports and the environment
surrounding the
tube. These differences, if unaccounted for, result in a systematic error in
the observed density.
If other departures from the model are assumed negligibly small contributions
to the working
equations, they can be ignored. It is then possible to conclude the effects
arising from
temperature and pressure variations might be adequately determined, for the
purpose at hand,
from knowledge of the elastic constants and thermal expansion of the material
of construction
combined with a room temperature determination of two parameters. This
approach can only be
proven by comparison of densities determined with the particular tube and this
working equation
with values determined from the archival literature from methods with quite
different sources of
systematic error.
[0044] The coefficients may be determined by calibration over the required
temperature and
pressure range. For example, in one previous study reported in the literature,
the calibration
coefficients were determined from resonance frequency measurements with the
tube evacuated
and when filled with water. The temperature and pressure range of the
calibration measurements
were the same as those required for the fluid of unknown density. For
measurements at
temperatures between 298 and 575 K at pressure below 13.8 MPa, a fourth order
polynomial in
temperature was required to represent one calibration parameter, while a third
order polynomial
in temperature was required for the other combined with a linear term for
pressure. Over a
greater pressure range, additional terms may be required to adequately
accommodate the dilation
of the tube with pressure. Pressure compensation, which will significantly
reduce dilation, will
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result in an additional departure from the assumptions used to derive Eq. 1 as
well as reduce the
sensitivity of the instrument as defined by dfldp. It is also assumed that the
supports, clamps and
the bend in the tube are accommodated by the calibration parameters.
100451 The parameters K and L may be determined by calibration measurements
with at least
two reference liquids of known density, such as water and nitrogen, or with
one liquid of known
density, for example, water, and with vacuum. Thus, the calibration may be
performed with
fluids that have I < 1 mPa.s that may not be equivalent to the viscosity of
the unknown. Thus,
neglecting viscosity, Eq. 1 can be used to obtain Eq. 5:
p=K(T,p)1 f2 +L(T,p)¨ AM)! p (5)
[00461 In general, the response of a vibrating object depends on either the
ratio or quotient of
density and viscosity. Instruments can be formed for which the parameter
measured, for
example resonant frequency, can be made more sensitive to one property or the
other by choice
of, for example, geometry. However, the working equations have assumed the
properties are
separable that is clearly an ideal case.
[0047] Another source of error arises from the fluid electrical
conductivity that is in parallel
with the tube conductivity. For operation with a highly conducting fluid, such
as mercury, it
might be necessary to alter the mechanical and electrical arrangement of the
densimeter.
However, provided the electrical resistance of the whole tube compared to that
of the clamped U-
section is large (at least a factor of the order of 100 greater), then the two
ends of the tube can be
shorted electrically at a fluid handling manifold without significantly
reducing the signal.
[00481 The mechanical stability and the effect of electrically conducting
fluid may be
improved by removing both the insulating material in the support between the
legs of the tube
and bolts clamping the parts together. This can be achieved by inductively
coupling the signals to
and from the tube. In this case, both legs of the U-tube are attached, by
welding when metal is
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used, to a metal plate that forms an electrically closed loop. The plate also
holds two
transformers, one couples the driving current into the loop, while the other
detects the current
circulating through the loop. This arrangement prevents operation with fluid
other than air
outside the tube. At resonance, the current is decreased by the motional EMF.
To match the low
impedance of the oscillator loop with the high impedance of synthesizer and
detector, each
transformer requires multiple turns on the winding placed around a ferrite
toroidal core. In this
case, the mica insulation used in the support is replaced by that used on the
ferrite cores. The
insulation is not subject to a compressive force. Indeed, the long-term
stability of the
transformers used to excite and detect the resonance only contribute to the
circuit sensitivity, not
the resonance frequency that determines density.
[0049] In view of all of the above, the present disclosure introduces means
for calibration
and reduction of systematic errors, in the context of using a vibrating U-tube
densimeter in a
wireline or drillstring conveyed logging tool for down-hole fluid analysis,.
For example, Fig. 5
is a schematic view of a logging tool 500 comprising two essentially identical
densimeters 510a
and 510b, where one densimeter 510b is exposed to a fluid of known density and
viscosity from
an internal reservoir 511, and the other densimeter 510a is exposed to the
unknown fluid via a
sampling probe 504. The reference fluid in the tank 511 may be or comprise
water, hydraulic
oil, air and/or other fluids. Alternatively, the tank 511 may be substantially
void of contents
(e.g., vacuum).
[0050] The logging tool 500 may form at least a portion of one or more of
the modules
shown in Figs. 1A, 1B and/or 2. Thus, for example, the logging tool 500 may
include a housing
502 that contains the sampling probe 504 with a seal (e.g., packer) 506 that
is used to acquire an
aliquot of hydrocarbon from the formation 508. The hydrocarbon may be
mobilized by a method
such as heating and/or diluent injection, among others. As such hydrocarbon
mobilization is
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well known in the art, the various components needed for such mobilization are
not illustrated in
the tool 500, but are nonetheless within the scope of the present disclosure.
The logging tool 500
may also comprise a pump 514 configured to assist in the flow of sampled
hydrocarbon within
the tool 500. In this context, the logging tool 500 may further comprise a
number of check, two-
way, three-way, and/or other valves, as well as a controller 516 which may be
in wired and/or
wireless communication with the pump 514, valves, and/or other components of
the logging tool
500 (although, for the sake of clarity, such valves and means of communication
are not shown).
For example, the controller 516 may at least partially operate the valves to
direct the flow of
sampled hydrocarbon from the probe 504 to various components of the logging
tool 500.
[0051] As mentioned above, the logging tool 500 also comprises two
essentially identical
densimeters 510a, 510b. The densimeters 510a, 510b may each be substantially
as described
above and/or shown in Figs. 3 and/or 4A-D, or otherwise within the scope of
the present
disclosure. In operation, the sample acquired from the formation 508 is
directed from the probe
504 to the densimeter 510a, perhaps via operation of the pump 514. At or near
the same time, a
sample of a known fluid is directed from the fluid tank 511 to the densimeter
510b, perhaps via
operation of the pump 514 and/or another pump within the tool 500. Operation
of the
densimeters 510a, 510b may be via the controller 516, other components of the
logging tool 500,
and/or surface equipment.
[0052] The logging tool 500 may also comprise an analyzer 512. The analyzer
512 may be
configured to receive output data from the densimeters 510a, 510b to be
utilized for further
determination of the parameters of the sampled hydrocarbon. The analyzer 512
may also or
alternatively be configured to perform its own analysis of the sampled
hydrocarbon, such as in
embodiments in which the analyzer is or comprises an optical fluid analyzer,
spectrometer,
chromato graph, and/or other analysis means. Operation of the analyzer 512 may
be independent
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and/or at least partially controlled by the controller 516, other components
of the logging tool
500, and/or surface equipment.
[0053] Such a vibrating U-tube densimeter tool may offer advantages for
applications in
wire-line and while-drilling applications that perform logging while drilling
(LWD). This dual
role arises from the relatively low tube mass and, thus, it is well suited to
sustaining shock that
imparts rapid and larges changes in local accelerations to the device and thus
force. This means
an in situ calibration is required.
[0054] The calibration procedure disclosed herein is particularly suited to
down-hole fluid
analysis because of the environment found down-hole. That is, in the absence
of fluid flow, the
down-hole temperature and pressure are constant relative to the variations in
the transition to a
down-hole depth.
[0055] The proposed procedure also eliminates the requirement to calibrate
each tube prior to
use and, in some circumstances, after use. The two tubes may be manufactured
in the same
process. During analysis and/or calibration, one tube is exposed to the
unknown fluid and the
other tube is filled with a fluid for which the density is known. Both tubes
are exposed to a gas
at the same pressure of about 0.1 MPa and at a pressure less than 1 MPa. The
density of the
unknown fluid is then determined from a ratio of the two measured frequencies
for the two tubes,
resulting in an equation of the form:
p(R){K(A, T,p)I f2 (A)+L(A,T,p y (6)
p( A) =
IK(R, T, p)I f (R)+ L(R, T , p)}
where A refers to the unknown fluid and R refers to the reference fluid.
Assuming, as may be
achieved when the tubes are constructed from the same material source using
the same
procedure, K(R, T, p) = K(A, T, p) and L(R, T, p)= L(A, T, p), Eq. 6 reduces
to:
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p(A) = p(R){K 1 f 2 (A) y (7)
1K I f2(R)+L}
Thus, K and L can be determined for each tube at measurements with the fluid
of known density
at ambient pressure and temperature. Eq. 6 continuously accommodates the
variation in the
tubes in response to temperature and pressure, provided it is acceptable to
assume the equality of
the calibration parameters. For an idealized model, the parameter L is
proportional to the ratio of
the mass of the vibrating tube A to the volume of fluid of unknown density V,
and if K>> L,
then Eq. 7 reduces to:
f2(A)
p(A) p(R) 2 (8)
f (R)
[0056] Alternatively, three tubes can be used. Fig. 6 is a schematic view
of another
embodiment of the logging tool 500 shown in Fig. 5, herein designated by
reference numeral
600. The logging tool 600 may form at least a portion of one or more of the
modules shown in
Figs. 1A, 113 and/or 2. The logging tool 600 shown in Fig. 6 may be
substantially similar to the
logging tool 500 shown in Fig. 5. However, the logging tool 600 comprises
three densimeters
510a, 510b and 510c. In operation, one densimeter 510a is exposed to the
sampled hydrocarbon,
and the other two densimeters 510b and 510c are exposed to fluid of known
thermophysical
properties. Operation of the logging tool 600 may otherwise be similar to that
of the logging tool
500 shown in Fig. 5.
[0057] In one embodiment utilizing such a configuration, densimeter 510a is
exposed to the
sampled hydrocarbon of unknown density, densimeter 510b is exposed to a fluid
of known
density, and densimeter 510c is filled with another fluid of known density.
However, the density
of the fluid in densimeter 510b is less than the unknown density of the
sampled hydrocarbon
(e.g., a vacuum), while the density of the fluid in densimeter 510c is greater
than the unknown
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density of the sampled hydrocarbon (e.g., water). Thereafter, a series of
equations similar to
those described above in reference to Fig. 5 may be used to determine the
density of the
unknown fluid sampled from the formation 508.
[0058] Fig. 7 is a schematic view of another embodiment of a logging tool
700 within the
scope of the present disclosure. The logging tool 700 may form at least a
portion of one or more
of the modules shown in Figs. 1A, 1B and/or 2. Aspects of the logging tool 700
shown in Fig. 7
may be used in conjunction with either of the tools 500 and 600 shown in Figs.
5 and 6,
respectively. However, for the sake of clarity, only the embodiment resembling
tool 500 of Fig.
is shown in Fig. 7.
[0059] In addition to the components shown in Figs. 5 and/or 6, the logging
tool 700
comprises a bellows or piston-in-cylinder arrangement 730 configured to
balance the pressure of
the known fluid (in tank 511) and the unknown fluid (from probe 504). For
example, the
bellows 730 may comprise an internal cavity separated into two chambers by an
internal member
732. The internal member 732 may comprise a piston, diaphragm, and/or other
flexible or
movable member configured to balance the pressure between the two chambers. In
operation,
the sampled hydrocarbon is directed from the probe 504 to one of the chambers
and then to the
densimeter 510a, whereas the known fluid is directed form the tank 511 to the
other chamber and
then to the densimeter 510b. Operation of the logging tool 700 may otherwise
be similar to that
of the logging tool 500 shown in Fig. 5.
[0060] Fig. 8 is a schematic view of another embodiment of a logging tool
800 within the
scope of the present disclosure. The logging tool 800 may form at least a
portion of one or more
of the modules shown in Figs. 1A, 1B and/or 2. Aspects of the logging tool 800
shown in Fig. 8
may be used in conjunction with either of the tools 500, 600 and 700 shown in
Figs. 5, 6 and 7,
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respectively, However, for the sake of clarity, only the embodiment resembling
tool 500 of Fig.
is shown in Fig. 8.
[0061] In addition to the components shown in Figs. 5, 6 and/or 7, the
logging tool 800
comprises two densimeters 510a, 510b which may or may not be identical. The
logging tool 800
also comprises means for exposing both densimeters 510a, 510b to the same
temperature during
their analyses of the known and unknown fluids. For example, the logging tool
800 may
comprise one or more heating elements 840 positioned adjacent or proximate one
or more of the
densimeters 510a, 510b. The heating elements 840 may each be or comprise a
resistive heater,
among other types, and may be controlled independently or by the controller
516. For example,
the controller 516 may be configured to operate the heating elements 840 such
that the
temperature of the densimeters 510a, 510b are substantially the same during
operation of the
densimeters.
[0062] For oilfield operations, the temperature range is limited. Aspects
of the tool 800 may
allow performing a calibration at a temperature close to that required for
operation. This may
considerably reduce the number of calibration measurements.
[0063] Fig. 9 is a flow-chart diagram of a method 900 of obtaining downhole
the density of
sampled hydrocarbon using, for example, the logging tool 500 shown in Fig. 5,
the logging tool
600 shown in Fig. 6, the logging tool 700 shown in Fig. 7, and/or the logging
tool 800 shown in
Fig. 8, among others within the scope of the present disclosure. The method
900 may also be
performed via and/or within at least a portion of one or more of the modules
shown in Figs. 1A,
1B and/or 2.
[0064] In step 905, the resonance frequency of the vibrating U-tube of a
first densimeter is
measured. The first densimeter comprises the unknown fluid obtained from the
formation. In
step 910, the resonance frequency of the vibrating U-tube of a second
densimeter is measured.
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The second densimeter comprises the known fluid obtained from, for example, an
internal
reservoir. In an optional step 915, the resonance frequency of the vibrating U-
tube of an optional
third densimeter may be measured. The third densimeter comprises a known fluid
obtained
from, for example, an internal reservoir, and may have a density greater than
or less than the
density of the known fluid in the second densimeter. Two or more of the steps
905, 910 and 915
may be performed substantially simultaneously.
[0065] A subsequent step 920 comprises determining the ratio(s) of the
resonance
frequencies that were determined during the previous steps. Thereafter, in
step 925, the density
of the sampled hydrocarbon is obtained from the working equations described
herein, using the
ratio(s) of resonance frequencies and the known thermophysical properties of
the reference
fluid(s).
[0066] Fig. 10 is a schematic view of another embodiment of a logging tool
1000 within the
scope of the present disclosure. The logging tool 1000 may form at least a
portion of one or
more of the modules shown in Figs. 1A, 1B and/or 2. Aspects of the logging
tool 1000 shown in
Fig. 10 may be used in conjunction with either of the tools 500, 600, 700 and
800 shown in Figs.
5, 6, 7 and 8, respectively. However, for the sake of clarity, only the
embodiment resembling
tool 500 of Fig. 5 is shown in Fig. 10.
[0067] In addition to the components shown in Figs. 5, 6, 7 and/or 8, the
logging tool 1000
comprises a viscosity measuring device 1050. For example, the viscosity
measuring device 1050
may be or comprise a vibrating wire viscometer. However, other viscosity
measuring devices
are also within the scope of the present disclosure. The viscosity measuring
device 1050 may be
positioned in the logging tool 1000 in place of one or more of the densimeters
described above,
or in addition thereto.
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[0068] In operation, the viscosity measurement obtained by the viscosity
measuring device
1050 may be used to make a correction to the density of the unknown fluid as
determined using
the densimeters 510a and 510b. This correction based on viscosity might be
achieved by an
empirical equation similar to Eq. 3. This requires an estimate of viscosity,
such as that which
might be obi ained from measurements with a vibrating wire viscometer or
capillary viscometer,
among other methods and/or apparatus that may be used to determine viscosity
within the scope
of the present disclosure. If a vibrating object is used to provide viscosity,
this will require an
estimate of density, and thus the analyses will need to be iterated until the
obtained values of
density and 'viscosity vary fractionally by less than the estimated
uncertainty in the measurement.
[0069] For example, Fig. 11 is a flow-chart diagram of an iterative method
1100 for using
the tool 1000 shown in Fig. 10. The method 1100 may be performed via and/or
within at least a
portion of one or more of the modules shown in Figs. 1A, 1B and/or 2. For
example, the method
1100 may be performed via and/or within the logging tool 500 shown in Fig. 5,
the logging tool
600 shown in Fig. 6, the logging tool 700 shown in Fig. 7, and/or the logging
tool 800 shown in
Fig. 8, among others within the scope of the present disclosure. The method
1100 comprises
iterations of the method 900 shown in Fig. 9, where each iteration includes
the additional step of
measuring the viscosity of the unknown fluid using the viscosity measuring
device 1050 shown
in Fig. 10.
[0070] In step 905a, the resonance frequency of the vibrating U-tube of a
first densimeter is
measured. The first densimeter comprises the unknown fluid obtained from the
formation. In
step 910a, the resonance frequency of the vibrating U-tube of a second
densimeter is measured.
The second densimeter comprises a known fluid obtained from, for example, an
internal
reservoir. In an optional step 915a, the resonance frequency of the vibrating
U-tube of an
optional third densimeter may be measured. The third densimeter comprises a
known fluid
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Attorney Docket No. 20.3156
Customer No. 23718
obtained from, for example, an internal reservoir, and may have a density
greater than or less
than the density of the known fluid in the second densimeter. Two or more of
the steps 905a,
910a and 915a may be performed substantially simultaneously. The method 1100
may also
comprise only the step 905a, in which the lone densimeter measures the density
of only the
unknown fluid.
[0071] A subsequent step 920a comprises determining the ratio(s) of the
resonance
frequencies that were determined during the previous steps. Thereafter, in
step 925a, the density
of the sampled hydrocarbon is obtained from the working equations described
herein, using the
ratio(s) of resonance frequencies and the known thermophysical properties of
the reference
fluid(s).
[0072] In a subsequent step 1105a, the viscosity of the unknown fluid is
measured using a
vibrating wi re viscometer and/or other viscosity measuring device. This step
1105a and the
previous steps 905a, 910a, 915a, 920a and 925a are then performed a second
time.
[0073] Thus, in step 905b, the resonance frequency of the vibrating U-tube
of the first
densimeter is measured. The first densimeter again comprises the unknown fluid
obtained from
the reservoir. In step 910b, the resonance frequency of the vibrating U-tube
of the second
densimeter is measured. The second densimeter again comprises the known fluid
obtained from,
for example, an internal reservoir. In an optional step 915b, the resonance
frequency of the
vibrating U-tube of the optional third densimeter may be measured. The third
densimeter again
comprises the known fluid obtained from, for example, an internal reservoir,
possibly having a
density greater than or less than the density of the known fluid in the second
densimeter. Two or
more of the steps 905b, 910b and 915b may be performed substantially
simultaneously. The
method 1100 may also comprise only the step 905b, in which the lone densimeter
measures the
density of only the unknown fluid.
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[0074] A subsequent step 920b comprises once again determining the ratio(s)
of the
resonance frequencies that were determined during the immediately previous
iteration of steps
905b, 910b and 915b. Thereafter, in step 925b, the density of the sampled
hydrocarbon is
recalculated from the working equations described herein, using the ratio(s)
of resonance
frequencies and the known thermophysical properties of the reference fluid(s).
[0075] In a subsequent step 1105b, the viscosity of the unknown fluid is
again measured
using the vibrating wire viscometer and/or other viscosity measuring device.
During a
subsequent decisional step 1110, it is determined whether the variation of the
density and
viscosity values of each of the two previous iterations of measurements is
less than an estimated
uncertainty. If not, then the method 1100 returns to steps 905b, 910b and 915b
to perform
another iteration. This continues until an acceptable level of variation is
attained. Thereafter, the
method 1100 may end or continue to other steps not described herein.
[0076] Fig. 12 is a flow-chart diagram of a method 1200 of obtaining
downhole the density
of sampled hydrocarbon using, for example, the logging tool 500 shown in Fig.
5, the logging
tool 600 shown in Fig. 6, the logging tool 700 shown in Fig. 7, the logging
tool 800 shown in
Fig. 8, and/or the logging tool 1000 shown in Fig. 10, among others within the
scope of the
present disclosure. The method 1200 may also be performed via and/or within at
least a portion
of one or more of the modules shown in Figs. 1A, 1B and/or 2.
[0077] More specifically, the method 1200 may comprise determining erosion
and/or
corrosion of the U-tube wall and precipitation within or outside the U-tube,
as these factors may
also be employed to correct the density measurement obtained using a logging
tool within the
scope of the present disclosure. Generally, when two U-tubes are filled with a
fluid of known
thermophysical properties, the effect of erosion on the tube previously
exposed to the unknown
CA 02699931 2010-04-13
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Customer No. 23718
fluid can be determined. During operation, the U-tube exposed to fluids of
unknown and known
density can be exchanged to minimize the effect of erosion, corrosion and
precipitation.
[0078] In step 905, the resonance frequency of the vibrating U-tube of a
first densimeter is
measured. The first densimeter comprises the unknown fluid obtained from the
reservoir. In
step 910, the resonance frequency of the vibrating U-tube of a second
densimeter is measured.
The second densimeter comprises the known fluid obtained from, for example, an
internal
reservoir. The steps 905 and 910 may be performed substantially
simultaneously.
[0079] A subsequent step 920 comprises determining the ratio(s) of the
resonance
frequencies that were determined during the previous steps. Thereafter, in
step 925, the density
of the sampled hydrocarbon is obtained from the working equations described
herein, using the
ratio(s) of resonance frequencies and the known thermophysical properties of
the reference
fluid(s).
[0080] A subsequent step 1205 comprises again measuring the resonance
frequency of the
vibrating U-tube of the first densimeter, but this time the first densimeter
comprises the known
fluid instead of the unknown fluid. The method 1200 then proceeds to step
1210, during which
the data obtained from the first densimeter with the unknown fluid during step
905 is used in
conjunction with the data obtained from the first densimeter with the known
fluid during step
1205 to determine what effect erosion, corrosion and/or precipitation may have
had on the
determination of the unknown fluid density. This information may then be
employed during a
subsequent step 1215 to correct the density of the unknown fluid obtained
during step 925.
[0081] In each of the above-described embodiments, as well as other
embodiments within
the scope of the present disclosure, the coefficients K and L may be expressed
in terms of the
elastic constants and thermal expansion of the material used to form the U-
tube. However, the
U-tube is affected by the environment in which it is housed, as well as the
mounting
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arrangemeni, which depends on the detection system to be used, as well as the
properties of the
fluid, if any, that surrounds the U-tube. Thus, additional calibration
coefficients may be required
to accommodate, for example, the clamping system. In situ acoustic measurement
of the U-
tube's mechanical constants may be used to provide data regarding the elastic
constants,
although doing so may require transducers that are attached to the U-tube and
thus act as
additional appendages and, more significantly, sources of potential systematic
errors and
variations in the U-tube's physical properties. This approach may provide a
significant
improvement in long-term stability for an instrument continually exposed to
fluid and variations
in temperature pressure, but without recourse to re-calibration. That is, it
is suited to permanent
sensing and not short-term, down-hole fluid analyses.
[0082] For oilfield operations, the U-tube may comprise a composition
selected for high
tensile strength and corrosion resistance, such as Hastelloy, Inconel and/or
other alloys
developed for production of hydrocarbons or pure metals such as titanium.
However, other
materials are also within the scope of the present disclosure.
[0083] In view of all of the above, it should be readily apparent to those
skilled in the
pertinent art that the present disclosure introduces a downhole logging tool
comprising a
reservoir containing a first fluid having a first density that is known, a
first densimeter
configured to receive the first fluid from the reservoir and output a first
resonance frequency
related to the first density, a second densimeter configured to receive a
second fluid from a
downhole formation proximate the logging tool and output a second resonance
frequency related
to a second density of the second fluid that is unknown, and an analyzer
configured to determine
downhole the second density based on the known first density, the first
resonance frequency
received from the first densimeter, and the second resonance frequency
received from the second
densimeter. Each of the first and second densimeters may comprise a vibrating
tube densimeter.
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The first fluid having the known density may be selected from the group
consisting of water,
hydraulic oil and methylbenzene.
[0084] The reservoir may be a first reservoir, in which case the logging
tool may further
comprise a second reservoir containing a third fluid having a third density
that is known, and a
third densimeter configured to receive the third fluid from the second
reservoir and output a third
resonance frequency related to the third density, wherein the analyzer is
configured to determine
downhole the second density based on the known first density, the first
resonance frequency
received from the first densimeter, the second resonance frequency received
from the second
densimeter, and the third resonance frequency received from the third
densimeter. The first
density may be less than an estimated value of the second density, and the
third density may be
greater than the estimated value of the second density.
[0085] The downhole logging tool may further comprise a pressure balancing
device
configured to balance a first pressure of the first fluid and a second
pressure of the second fluid.
The pressure balancing device may comprise first and second chambers separated
by a pressure
balancing element, wherein the first chamber is fluidly connected between the
reservoir and the
first densimeter, and wherein the second chamber is fluidly connected between
the formation and
the second densimeter.
[0086] The downhole logging tool may further comprise a first heater (or
cooler) configured
to adjust a temperature of the first fluid when in the first densimeter, and a
second heater (or
cooler) configured to adjust a temperature of the second fluid when in the
second densimeter.
[0087] The downhole logging tool may further comprise a viscometer
configured to
determine a viscosity of the second fluid. The viscometer may comprise a
vibrating wire
viscometer.
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[0088] The present disclosure also introduces a method of in-situ formation
fluid evaluation
comprising measuring a first resonance frequency of a first fluid using a
first densimeter
downhole, wherein a first density of the first fluid is known, and measuring a
second resonance
frequency of a second fluid using a second densimeter downhole, wherein the
second fluid is a
formation fluid received by the second densimeter downhole, and wherein a
second density of
the second fluid is unknown. The method further comprises determining the
second density of
the second fluid using the first and second resonance frequencies and the
known first density.
Each of the first and second densimeters may comprise a vibrating tube
densimeter. The first
fluid may be selected from the group consisting of water, hydraulic oil and
methylbenzene.
[0089] The method may further comprise measuring a third resonance
frequency of a third
fluid using a third densimeter downhole, wherein a third density of the third
fluid is known, and
wherein determining the second density of the second fluid comprises using the
first, second and
third resonance frequencies and the known first and third densities. The first
density may be less
than an estimated value of the second density, and the third density may be
greater than the
estimated value of the second density.
[0090] The method may further comprise balancing a first pressure of the
first fluid and a
second pressure of the second fluid. The method may further comprise heating
at least one of the
first and second fluids when in the first and second densimeters,
respectively, so that
temperatures of the first and second fluids are substantially equivalent
during measuring of the
first and second resonance frequencies.
[0091] The method may further comprise determining a viscosity of the
second fluid.
[0092] The method may further comprise iteratively determining the
viscosity and the
second density of the second fluid until a variation of the determined
viscosity and second
density is less than an estimated uncertainty.
29
CA 02699931 2013-06-05
' 79350-298
[0093] The method may further comprise measuring a third resonance
frequency of
the first fluid using the second densimeter to correct the determined second
density of the
second fluid based on whether erosion, corrosion or precipitation exists
within the second
densimeter.
[0094] The foregoing outlines features of several embodiments so that those
skilled in
the art may better understand the aspects of the present disclosure. Those
skilled in the art
should appreciate that they may readily use the present disclosure as a basis
for designing or
modifying other processes and structures for carrying out the same purposes
and/or achieving
the same advantages of the embodiments introduced herein. Those skilled in the
art should
also realize that such equivalent constructions do not depart from the scope
of the present
disclosure, and that they may make various changes, substitutions and
alterations herein
without departing from the scope of the present disclosure.
