downhole viscosity measurement: revealing reservoir...
TRANSCRIPT
SPWLA 55th
Annual Logging Symposium, May 18-22, 2014
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DOWNHOLE VISCOSITY MEASUREMENT: REVEALING RESERVOIR
FLUID COMPLEXITIES AND ARCHITECTURE
Vinay K. Mishra, Beatriz E. Barbosa (Schlumberger), Brian LeCompte (Murphy Oil) , Yoko Morikami, Christopher
Harrison, Kasumi Fujii, Cosan Ayan, Li Chen, Hadrien Dumont, David F. Diaz, Oliver C. Mullins (Schlumberger)
Copyright 2014, held jointly by the Society of Petrophysicists and Well Log
Analysts (SPWLA) and the submitting authors.
This paper was prepared for presentation at the SPWLA 55th Annual Logging
Symposium held in Abu Dhabi, United Arab Emirates, May 18-22, 2014.
ABSTRACT
Knowledge of formation fluid viscosity and its vertical
and lateral variations are important for reservoir
management and determining field commerciality.
Productivity and fluid displacement efficiency are
directly related to fluid mobility, which, in turn, is
greatly influenced by fluid viscosity. Therefore,
viscosity is a critical parameter for estimating the
economic value of a hydrocarbon reservoir and
also for analyzing compositional gradients and
vertical and horizontal reservoir connectivity.
The conventional methods for obtaining formation fluid
viscosity are laboratory analysis at surface and
pressure/volume/temperature (PVT) correlations.
However, deducing viscosity from correlations
introduces uncertainties owing to the inherent
assumptions. Surface viscosity measurement may be
affected by irreversible alteration of the sampled fluid
through pressure and temperature changes, as well as
related effects of long-term sample storage.
A new downhole sensor for a wireline formation tester
tool has been introduced to measure the viscosity of
hydrocarbons. The new viscosity sensor uses a
vibrating-wire (VW) measurement method with well-
established analytical equations for interpretation.
Downhole field testing of an experimental prototype
has been conducted, with extensive laboratory tests to
validate the sensor performance in viscosities ranging
from light to heavy oil and at a wide range of well
environments. The vibrating wire viscometer sensor
meets requirements not only for measurement
performance, but also for operations in downhole
applications, and possesses the following properties:
High-pressure and high-temperature
qualification (25,000 psi and 347° F)
Fast response time with an accurate viscosity
measurement provided every second
Installation in standard downhole fluid
analyzer modules in wireline formation testers,
made possible by recent miniaturization
Deployment in sections with immiscible
contamination
Accurate temperature measurement of flowing
fluid
In addition to overall results for field tests, field
examples of viscosity measurements are presented from
a deepwater Gulf of Mexico well. In-situ measurements
were performed by flowing noncontaminated reservoir
oil using the focused sampling technique. The
measurement of bottomhole flowing pressure and
temperature, and other fluid properties such as density
and gas/oil ratio (GOR), together with viscosity,
allowed comprehensive analysis of the integrated
dataset to understand the reservoir.
INTRODUCTION
The importance of viscosity for oil production,
completion design and overall reservoir management is
very well understood. Viscosity not only controls
productivity and displacement efficiency of the
reservoir, but plays a major role when designing subsea
hardware and pipelines and for managing flow
assurance related concerns. Accurate and timely
viscosity data is of significant importance for the
optimization of the production phase of every well.
A new miniaturized vibrating wire sensor has been
developed to measure the viscosity of live
hydrocarbons, from a range of 0.2 to 300 cP, under
flowing conditions, in a reasonably clean environment
(Khalil et al., 2008; Godefroy et al., 2010a, 2010b;
Daungkaew et al., 2012).
The vibrating wire sensor consists of a thin metal wire
held taut at both ends in a sensor body (Fig. 1). The
vibrating wire excitation and the detection of its motion
can be performed with either steady–state or transient
SPWLA 55th
Annual Logging Symposium, May 18-22, 2014
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methods.
The steady-state approach to measure fluid viscosity
excites the wire with an oscillatory current at each
frequency and simultaneously measures the resulting
voltage (curiously referred to by the misnomer
“electromotive force,” and more succinctly as emf) that
is produced by the motion of the wire when subjected to
a magnetic field. In contrast, the transient method
briefly excites the wire at its resonant frequency, and,
after extinction of the excitation, measures the resulting
ring-down voltage as the wire loses amplitude. The
latter method is used here because of its rapid
measurement time as compared to the former. In both
methods, the wire experiences a strong magnetic field
(here, approximately 0.5 Tesla) perpendicular to its
axis, thereby providing a Lorentz force which drives the
transverse oscillation of the wire. The working
equations used to determine the viscosity from
measurements of the transient method have been
discussed in detail elsewhere and were used without
modification (Retsina et al. 1986, 1987; Assael et al.,
1991; Sullivan et al., 2009).
The emf ring-down signal consists of an exponentially
damped sinusoidal ring-down (similar to that of
damped simple harmonic motion) such that the induced
emf voltage V(t) is given by
)sin()( 0 teVtV t
’ .......................... (1) where V0 is the initial amplitude of the transient, the
decrement linked to the damping experienced by the
wire, the angular resonant frequency, and the phase
angle. This emf is created by the temporally changing
magnetic flux in a loop consisting of the wire as
dictated by Faraday’s law. In Equation 1, the decrement
is related to several properties, including fluid
density, but dominated by the fluid viscosity, enabling
the device to function as a viscometer. Two examples
are presented below (Fig. 2 and Fig. 3) that demonstrate
how the ring-down varies with viscosity. In each case,
the characteristic time of the ring-down [1/()] is
shown to be on the order of milliseconds, providing a
rapid measurement when implemented downhole. To
calculate viscosity, the vibrating wire sensor uses fluid
density as an input, which is provided by downhole
density sensor (vibrating rod or DV rod). In turn, the
vibrating rod can measure both fluid density and
viscosity under ideal conditions, but experience has
taught us that the installation of both sensors in the
toolstring allows for the most reliable measurement of
viscosity, even in difficult fluid conditions.
Fig. 2 After an electromagnetic excitation, similar to
the plucking of a guitar string, a long-lived ring-down
voltage is observed in a fluid of viscosity 4 cP where
Fig. 1 The vibrating wire (orange) is held taut by
two supports (poles) inside the flowline (black) of
the formation evaluation tester. Current (i) is
passed through the wire in the presence of a
magnetic field (B) resulting in an orthogonal force
(F) as given by the right-hand rule. The lateral
view is restricted to the vibrating wire in the flow
line; the top view includes the wire and external
magnets in the circular geometry of the sensor (see
Fig. 4).
F
iB
Fluid Flow
Lateral view
Top view
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Annual Logging Symposium, May 18-22, 2014
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the frequency is measured to be 1957 Hz and the time
constant 5.4 ms [1/()]. The voltage is generated by
the oscillatory motion of the wire as dictated by
Faraday’s law.
Fig. 3 In contrast to Fig. 2, a short-lived ring-down
(1.0 ms) is created in a high-viscosity fluid (104 cP).
The frequency here is 1851 Hz. For both this graph
and that in Fig. 2, agreement between data and model
is to the point that the two curves cannot be
distinguished.
One benefit of this design is its insensitivity to flow.
Documented benchmarking confirms that high flow
rates with viscous fluids parallel to the wire do not
detrimentally bias the measurement (Harrison et al.,
2007).
The miniature vibrating wire sensor shown in Fig. 4 and
Fig. 5 is qualified up to 347° F and 25,000 psi. The
sensor also includes a platinum resistance-temperature
detector thermometer. Altogether, including electronics,
the sensor body is 5 cm in diameter which allows it to
be installed in the downhole fluid analyzer of wireline
formation tester tool. This location enables the
measurement of the viscosity in close proximity to
other in-situ measurements, such as fluid density,
gas/oil ratio (GOR), and fluid composition, together
with pressure and temperature of the flowline.
Fig. 4 The vibrating wire sensor with integrated
electronics is small enough to fit in the palm of the
hand.
Fig. 5 VW sensor resting on tool, about to be installed
in the third sensor slot (also known as coffee-cup slots)
of the wireline formation evaluation tool that performs
downhole fluid analysis. The first slot is used for the
resistivity cell and the second slot for the DV-rod
sensor.
The vibrating wire body and the wire material are made
of alloys, with the latter having oleophilic properties,
enabling the sensor to measure the formation oil
viscosity even in the presence of water. During
laboratory measurements and field tests, it had been
determined that a high water fraction in the flowline
adds noise to the measurements. Fig. 6 presents the
results of the experiments with two different oils under
a nominal flow of 10 cm3/s: a hydraulic oil referred to
as Univis J13 and the pure hydrocarbon n-dodecane,
each possessing significantly disparate viscosities. For
the experiments with J13, the sensor continued to read
with accuracy better than 10% for water fractions up to
10%, but when the water fraction was increased to
30%, the standard deviation of the readings increased
significantly, although the average value remained the
SPWLA 55th
Annual Logging Symposium, May 18-22, 2014
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same. This experiment was confirmed with lighter oil,
n-dodecane, with a viscosity of 1.36 cP. In this case, the
measurement was still within the specifications at 10%
water fraction, although it was very noisy. At 40%, it
was visually confirmed that the dodecane was
emulsified with water and the effective fluid viscosity
was considered to be altered.
Fig. 6 Oil viscosity measurement in laboratory with
controlled water fraction with oils of two different
viscosities. The round marker indicates “median”
values of the readings.
The sensor behavior was also tested to determine its
performance in particulate-laden fluid flow (sand),
which occurs when testing unconsolidated reservoirs.
Fig. 7 shows the laboratory results. Results are first
presented (upper graph) from the vibrating wire
viscosity measurements of a particulate-free fluid where
the flow rate was varied from 8 to 15 cm3/s. In this
case, all the measured points are within the specified
uncertainty. When sand particles were added (up to 100
g/L, see lower graph), the error greatly increased at a
flow rate of 15 cm3/s, but reduction of the flow rate to 8
cm3/s significantly lowered the error, and the
measurement error fell within the specifications.
Therefore, during the field jobs, if the sensor was
providing data with a large degree of scatter, it could be
an indication of flowing sand, which can be reduced by
lowering the flow rate. The sensor design has been
qualified for flow rates up to 66 cm3/s (Godefroy et al.,
2010b).
Fig. 7 Experimental result on the effect of sand in
viscosity measurement.
The vibrating wire uses a permanent magnet that has
the potential to attract metallic debris and particles that
might be present in the flowline. The effect of magnetic
particles will be observed as a drift on the measurement
due to their physical interaction with the vibrating wire
sensor probe, thereby affecting the ring-down decay
and hence the viscosity measurement. To avoid this, it
is recommended to avoid circulating mud through the
wireline formation tester and to flush it before doing a
downhole job. Additional precautions are also taken to
minimize magnetic debris in the vibrating wire sensor,
including the installation of a magnet in the formation
evaluation tool flowline upstream of the sensor and the
installation of a ditch magnet at the rig.
During the field test campaign, a total of 34 jobs were
conducted in wells drilled with oil-base mud with
temperatures ranging from 40 to 150°C and pressures
from 2,300 to 25,000 psi (Fig. 8).
Flow with fluid with sand particles
15 cm3/s 8 cm3/s
sec
Flow with clean fluid
Flow rate varied between 15 to 8 cc/sec
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Annual Logging Symposium, May 18-22, 2014
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Fig. 8 Plot of pressure versus temperature during field
test jobs.
During field tests, a total of 43 hydrocarbon stations
were performed with vibrating wire sensor providing
good results, in this way adding value to the other in-
situ measurements present in the formation evaluation
tester and providing a complete map of data to facilitate
improved well evaluation. In certain cases, vibrating
wire viscosity results were complemented by vibrating
rod density and viscosity measurements. Having two
sensors in the formation tester tool provides in-situ
viscosity via two different sensing techniques; accurate
measurement by the vibrating wire sensor was achieved
in 95% of the cases. Both cases will be reviewed in
detail in the field examples described below.
FIELD EXAMPLES
Sampling and downhole fluid analysis (DFA),
including viscosity measurements, were performed in
two wells in a field in the deepwater environment of
Gulf of Mexico wherein the objective of both wells was
to properly evaluate the reservoir and to establish
important fluid characterization parameters and
connectivity.
In well 1, fluid sampling and DFA were performed at
six depths (four oil, one gas and one water station). In
well 2, fluid sampling and DFA were performed at six
oil stations and two water stations, acquiring a total of
11 pressure/volume/temperature (PVT) sample bottles
and two 1-gal chambers. Four of the test stations were
primarily for fluid characterization and compositional
gradient determination. After the wireline job detailed
laboratory analysis was performed on two of the oil
samples, and the laboratory viscosity results from an
electromagnetic viscometer (EMV) were compared to
the vibrating wire sensor measurements from the field
(log), as shown in Table 1. The comparison showed
good agreement, and the detailed results are presented
later in this paper.
Table 1: Laboratory and Downhole Viscosity (using
mini vibrating wire) Measurements
Laboratory Viscosity (EMV)
In-situ Viscosity (Log)
Sample 1 0.60cP 160 ºF, 5,965 psi
0.68 cP 146 ºF, 5,860 psi
Sample 2 0.72 cP 176 ºF,6,875 psi
0.78 cP 175 ºF, 6,745 psi
Though laboratory viscosity measurements were
performed for only two sample depths, downhole
viscosity was available for all of the 11 hydrocarbon
sampling and DFA stations. As the results of the field
test were positive, the viscosity data from the wireline
formation tester (WFT) for all stations were used in
reservoir evaluation to better understand the petroleum
system. DFA was exclusively performed on clean fluid
in the flowline and the samples acquired subsequently
confirmed contamination levels less than 5%. DFA
results for all stations across both wells are presented in
Table 2. Laboratory measured fluid properties results
are available for three stations which are noted for
comparison with DFA data. The DFA stations listed in
the table are also the sampling stations. The DFA
station numbers will be referenced to this table in
subsequent plots. Even though the laboratory analyses
of only three stations are shown in detail, the
contamination level for the other stations as reported by
the laboratory was approximately 3% or less.
Fig. 9a consists of a station plot (Well 2, DFA Station
#3) which includes viscosity, density, GOR, and fluid
composition. Pumpout data is also provided to
understand changes in flow rates. The horizontal axis
indicates the elapsed time in minutes. In this job, the
DFA tool was placed upstream, which means between
the sampling inlet device and the pump module. The
viscosity data (red) show a relaxation curve, which
corresponds to the cleanup process of the drilling-mud
by formation oil and which agrees with the other
downhole measurement data, such as GOR (green),
vibrating rod density (purple), and composition analysis
(middle plot). Flowing fluid fraction is shown at the
bottom section of the plot with green indicating oil.
From the log it is observed that the in-situ viscosity
reading was very stable after the cleanup and provided
an absolute viscosity value 0.68 cP at 146° F and 5,860
SPWLA 55th
Annual Logging Symposium, May 18-22, 2014
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psi. During part of the pumping duration (45 to 58
minutes), intermittent fluctuation in viscosity was
observed which was most likely due to solids flowing
next to or accumulating on the sensor. The in-situ
viscosity number is taken from the stabilized and
usually lowest values of the measurement; experience
teaches this to be the most accurate.
Fig. 9b shows the tested interval described above, in
more detail and including pressure and temperature.
The temperature reading was taken from the vibrating
wire sensor and was verified from pressure and
temperature sensor in the WFT tool.
Fig. 10a and 10b (Well 2, DFA Station 4) comprise
another station plot consisting of flowing fluid type, in-
situ composition, GOR, fluid density, and viscosity, the
latter two being from the vibrating rod and the vibrating
wire. From the log it is observed that the in-situ
viscosity reading was very stable after the cleanup and
provided a viscosity value of 0.62 cP at 148.5° F and
5,935psi. Viscosity measured from both of the sensors
is in good agreement providing high confidence in
downhole measurement. The temperature reading is
taken from vibrating wire sensor, which is also verified
from the pressure and temperature sensor in the DFA
tool. The pressure value, specified above, is the
flowline pressure measured by pressure gauge installed
in the DFA tool itself.
In Fig. 11, the results from DFA station 2 of well 1 are
presented; the viscosities from both the vibrating wire
and vibrating rod sensors are shown. Since the fluid
cleanup started during the pumpout phase of the station,
the viscosities from both sensors start to stabilize after
about 25 min of pumping. After this time period, the
vibrating rod viscosity starts drifting upwards, possibly
due to some type of fluid or solid sticking at the sensor.
Hence, only vibrating wire viscosity was used from this
station. The presence of two viscosity sensors in the
DFA tool simultaneously allows representative in-situ
viscosity measurements to be taken even in the
challenging flow conditions.
Table 2: Measured Fluid Properties, DFA Tool and Laboratory (PVT LAB)
DFA/
LAB
Depth
(ft)
GOR
(ft3/bbl)C1 (wt%) C2 (wt%)
C3-C5
(wt%)
C6+
(wt%)
DV-Rod
Dens.
(g/cm3)
Insitu
Viscosity
(cP)
Conta
minati
on (%)
Fluore
scence
Fluid
Type
Well 1
DFA 1 XX240 1423 13.17 1.91 5.21 79.7 0.692 0.6 <5 0.76 Oil
DFA 2 XX440 1101 10.43 1.43 5.39 82.75 0.714 0.81 <5 0.42 Oil
DFA 3 XX675 52029 85.54 0.1 3.1 11.25 0.288 0.2 <5 0.06 Gas
DFA 4 XX110 612 5.54 1.59 4.93 87.94 0.779 1.3 <5 0.36 Oil
DFA 5 XX140 536 4.8 1.49 4.62 89.08 0.78 1.3 <5 0.23 Oil
DFA 6 XX150 NA NA NA NA NA 0.979 NA <5 NA Water
Well 2
DFA 1 XX450 1352 12.67 2.05 4.44 80.84 0.698 0.6 <5 0.75 Oil
PVT LAB XX450 1160 10.86 1.13 6.06 81.95 0.684 NA 3.8 Oil
DFA 2 XX460 1274 12.02 1.9 4.56 81.52 0.702 0.65 <5 0.64 Oil
DFA 3 XX480 1274 12.23 2.12 4.15 81.5 0.702 0.68 <5 0.5 Oil
PVT LAB XX480 1187 10.37 1.1 6.41 82.12 0.698 0.6 2.5 Oil
DFA 4 XX010 1169 11 1.81 4.81 82.33 0.715 0.68 <5 0.47 Oil
DFA 5 XX130 1138 10.68 2.15 4.27 82.9 0.723 0.78 <5 0.54 Oil
PVT LAB XX130 990 8.87 1.23 5.87 82.14 0.721 0.72 2.4 Oil
DFA 6 XX240 620 5.74 1.52 4.43 88.31 0.767 1.12 <5 0.22 Oil
DFA 7 XX480 NA NA NA NA NA 0.979 NA <5 NA Water
DFA 8 XX150 NA NA NA NA NA 0.985 NA <5 NA Water
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Fig. 9a Well 2, DFA station 3, in-situ fluid analysis results including viscosity, density, GOR, and fluid
composition. Pumpout data is shown on middle graph to understand pumping duration. In-situ viscosity measured
by vibrating wire sensor (0.68 cP, red curve) at bottomhole flowing condition of pressure 5,860 psi and temperature
146° F is in close agreement with PVT laboratory measurement (0.60 cP, at a pressure of 5,965 psi and temperature
160o F)
Fig. 9b Well 2, DFA station 3, enlarged viscosity plot along with pressure and temperature variation. In-situ
stabilized viscosity of 0.68 cP is at bottomhole flowing condition of pressure 5,860 psi and temperature 146° F. PVT
laboratory viscosity measured at surface is corrected for reservoir condition, at a pressure of 5,965 psi and
temperature 160o F.
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Annual Logging Symposium, May 18-22, 2014
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Fig. 10a Well 2, DFA station 4, in-situ fluid analysis results including viscosities from vibrating wire (red) and
vibrating rod (black), vibrating rod density, GOR, and fluid composition. Pumpout data is also shown to understand
pumping duration and impact on measurements. The two viscosities match closely providing confidence in the
measurement. There is no noise affecting the measurement as observed from the smooth viscosity curves.
Fig. 10b Well 2, DFA station 4, enlarged view of Fig. 10a; in-situ viscosity (red and black) and density (blue) plots
along with pressure (blue, lower graph) and temperatures (black and red, lower graph). Pressure is measured from
the downhole fluid analysis tool. Temperature measured from both vibrating wire (red) and vibrating rod (black)
sensors are presented, and there is difference of approximately 3° F between the two.
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Fig. 11 Well 1, DFA station 2, in-situ fluid analysis results including viscosity from vibrating wire and vibrating
rod, density, GOR, fluid composition, and pumpout flow rate. As the fluid cleanup started with the pumpout, the in-
situ viscosity from both sensors (vibrating wire viscosity, red curve; vibrating rod viscosity, black curve) start
stabilizing (duration 10 to 25 min). Afterwards, the vibrating rod viscosity starts drifting upwards, possibly due to
some type of fluid or solid sticking on the sensor. Hence, only the vibrating wire viscosity was used from this
station. The presence of two viscosity sensors in the DFA tool allows representative in-situ viscosity measurement in
over 95% of the cases.
The PVT laboratory viscosity measurement results
were obtained with an EMV. As mentioned earlier,
two samples from different depths were analyzed,
each belonging to a different sand in the same well
(Well 2). The laboratory tests, presented in Table 1,
provided viscosity values of 0.60 cP for the first
sample, whereas the vibrating wire sensor showed
0.68 cP at slightly different pressure and temperature
conditions. The laboratory viscosity was measured at
surface and correlated to estimated reservoir
conditions. The downhole (DFA) viscosity was
measured at in-situ flowing pressure and temperature
conditions. For the second sample, the downhole
vibrating wire sensor measured a viscosity of 0.78 cP
while the laboratory measurement was 0.72 cP. For
both samples, the measurement agreed within the
range of the specifications (±10%). Additionally, the
sensor was able to see the slight difference of
viscosity between the stations tested in the same
reservoir, confirming the high precision of the
vibrating wire sensor, which is specified as 3%.
Fig. 12 is the composite plot of WFT measured
pressures and mobility, downhole fluid properties,
and basic logs such as gamma ray and induction array
resistivity. Plotted over the upper reservoir section,
the DFA data includes three oil stations and one
water station as shown in the depth track. Optical
density (OD), fluorescence, and viscosity show
consistent compositional variation across the
reservoir. Advanced equation of state (EOS)
modeling was performed with an asphaltene size of 2
nm. A very close match of EOS predicted curve with
measured OD confirms that the fluid is in equilibrium
and most likely connected. (Mishra et al. 2012;
Mullins et al., 2012). Reservoir connectivity
conclusion is also supported by other petrophysical
logs and geological information.
Fig. 13 is the composite plot produced by the WFT
across the lower sands in well 2 and includes
pressures, mobilities, downhole fluid properties, and
basic logs such as gamma ray, induction array
resistivity, and imaging log. The DFA/sampling
stations can be seen from the fluid composition
plotted as horizontal bars in depth track. DFA
measurements indicate that the top two stations
consist of oil, the next deepest station consists of
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water, and the bottom zone consists of oil. The DFA
measurements- especially optical density, viscosity,
and fluorescence -confirm that the bottommost sand
has much higher viscosity and darker color than the
middle sands. The presence of water zone confirms a
barrier, supporting the DFA measurements. Imaging
log and Gamma ray log indicate that the reservoir
above water zone, across two oil stations, is
heterogeneous with high degree of shaliness. While
the insitu measured viscosity and density show
standard variations in properties, the color indicates
low degree of reversal with higher OD at top. This
could possibly be due to localized accumulation of
asphaltene over shale beds/baffles. Such examples
emphasize the benefits of the integration of multiple
fluid properties measurement downhole.
Fig. 12 Well 2, composite DFA plot across upper reservoir. Depth track contains tested DFA/sampling interval with
the fluid composition plots. The top three stations indicate flowing oil and the bottom most (blue bar) indicates
flowing water. Viscosity and density are plotted in the fourth track from the left (green circle and red squares,
respectively). Second track from right consists of the GOR (green) along with fluid optical density (red circles). The
blue curve is computed from asphaltene equation of state modeling using 2 nm asphaltene sizes. The three measured
OD stations falling on EOS curve confirms the fluid is in equilibrium and the tested zones are most likely connected.
As it could be noted insitu viscosity and fluorescence measurements are also in agreement with the asphaltene
gradient. Density and GOR variations are very small.
Insitu Viscosity cP
Insitu Densityg/cc
GOR_IFA, ft3/bbl
0.2 Mobility 2000md/cP
Asphaltene EOS predicted curve
Measured Optical Density (OD)IFA Fluorescence
Array InductionResistivity
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Fig. 13 Well 2, Composite DFA plot across lower reservoir. DFA measurements indicate that the top two stations
consist of oil, the next station consists of water, and that the bottom zone is oil. The DFA measurements - especially
optical density, viscosity, and fluorescence - confirm that the bottom most sand has much higher viscosity and
darker color than the upper sands. Presence of water zone confirms a barrier supporting DFA measurements.
CONCLUSIONS
Fluid viscosity is one of the critical input parameters
in reservoir evaluation, with expected large variation
for compositionally graded reservoirs. However, it
has been one of the most difficult measurements to
achieve without an unacceptably high level of
uncertainty.
A new proven and robust DFA sensor, the vibrating
wire sensor, provides higher reliability to the in-situ
fluid viscosity measurement partially covered by the
vibrating rod, as each sensor operates with different
fluid mechanics with designs that could be affected in
different ways in challenging downhole environments.
Measurement of in-situ viscosity allows operators to
perform economic evaluation of reservoirs with more
data to support their conclusions, as there is no
constraint in the number of stations analyzed.
Furthermore, no additional logging time is required
to measure viscosity since pumpout times were
determined only by the amount of cleanup. The
miniaturization of the sensor allows it to be
conveniently installed in a slot in a WFT tool,
eliminating the need for an additional module in the
toolstring.
Measurements with the vibrating wire sensor were
performed in two wells in the deepwater Gulf of
Mexico in a light oil reservoir with a range of 29 to
30°API. The result show the applicability of the in-
situ viscosity measurements, integrated with other
DFA measurements and petrophysical and geological
logs, for reservoir connectivity, compositional
grading, and other major field decisions. These
measurements also provide valuable results for real-
time decisions such as acquiring clean fluid samples,
optimizing the sampling and DFA stations, and
performing reservoir fluid characterization.
ACKNOWLEDGMENT
The co-authors thank Schlumberger management for
approval for presenting this paper. We also thank
Murphy Oil and partners for approval for the
publication of field examples. We thank Sophie
Godefroy and Matthew Sullivan for useful
conversations.
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Annual Logging Symposium, May 18-22, 2014
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ABOUT THE AUTHORS
Vinay K. Mishra is Principal
reservoir engineer and domain
champion with Schlumberger,
Houston, TX. He provides
reservoir engineering support
primarily formation testing sampling and DFA for
Gulf of Mexico and Atlantic Canada operations.
Previously he has worked in different roles of
petroleum engineering based in Canada, Libya, Egypt
and India. He has co-authored over 25 publications in
international conferences including SPWLA and SPE.
He has done B.S. in Petroleum Engineering from
Indian School of Mines, Dhanbad, India. Vinay has
been committee member and session chairs in several
of SPE events. He is also registered with Association
of Professional Engineers and Geoscientists of
Alberta (APEGA)
Beatriz E. Barbosa is the Reservoir
Pressure & Sampling Product
Champion with Schlumberger,
Wireline HQ. Her responsibilities
are the alignment of the domain
road map with the industry needs
and development of the required
technologies. Previously she had
several managerial positions as Wireline Geomarket
manager (Peru, Colombia and Ecuador), Middle East
& Asia Wireline Training Center Manager and
Country Wireline operations manager. As a wireline
field engineer and sales representative Beatriz
worked in Angola, Colombia and Ecuador. She
holds a degree in Civil Engineering from Los Andes
University in Bogota Colombia (2001).
SPWLA 55th
Annual Logging Symposium, May 18-22, 2014
13
Brian LeCompte is a Sr.
Petrophysicist with Murphy Oil
where he provides petrophysical
support for the Gulf of Mexico
and Atlantic Margins regions.
This includes all aspects of rock,
fluid, and pressure analysis for
live well operations, new ventures, development, and
exploration well planning. Brian previously worked
with Baker Hughes in their research and development
group from 2006 - 2010 in the areas of mineralogy
and shale evaluation. Brian has a M. Eng. in
Petroleum Engineering from Texas A&M University
and a B.A. in philosophy and mathematics from the
University of St. Thomas in Houston, TX. He holds
3 US Patents and has published numerous papers
with SPE and SPWLA.
Yoko Morikami is senior physics engineer working
on downhole fluid analysis sensors at Schlumberger
K.K. She graduated from Osaka University, Japan,
with M.S. in physics.
Christopher Harrison is currently
a program manager at
Schlumberger-Doll Research in
Cambridge, MA where he has
worked for the past 10 years. He
has focused on the development of
miniaturized sensors to measure fluid properties, such
as viscosity, density, and saturation pressure. He
holds a doctorate in physics from Princeton
University.
Kasumi Fujii is a project manager in fluid analysis
and sensors group at Schlumberger K.K. She
graduated from Ochanomizu Univ., Japan with M.S.
in physics.
Dr. Cosan Ayan is a Reservoir
Engineering Advisor for Schlumberger
Oilfield Services, based in Paris,
France. Currently he is the Wireline
Headquarters Reservoir Engineering &
Management Technical Director. Dr.
Ayan leads Schlumberger Wireline Reservoir
Engineering team worldwide and had similar
headquarters positions for Petro-technical Services
and Testing Services. During his twenty four years
with Schlumberger, he held Reservoir Engineering
positions in Dubai, Cairo, Abu Dhabi, Aberdeen,
Houston, Jakarta and Paris. He works on
interpretation and development projects, focusing on
wireline formation testers, transient well tests,
production logging, and reservoir monitoring and
reservoir management.
Dr. Ayan holds BS degree from Middle East
Technical University-Ankara (1981), MS (1985) and
Ph.D. (1988) degrees from Texas A&M University-
College Station all in Petroleum Engineering. He is
the author of more than 60 technical papers on
transient testing, reservoir monitoring and reservoir
engineering and has several patents on interpretation,
downhole tools and acquisition techniques. He has
been on several technical committees for SPE, served
as a SPE Distinguished Lecturer during 2005-2006
and as Executive Editor-for SPE Reservoir
Evaluation & Engineering Journal, 2007-2010.
Li Chen is a senior reservoir
engineer and associate reservoir
domain champion with
Schlumberger, Houston, Texas, USA.
He has the M.S. in Reservoir
Engineering from China Petroleum University. His
previous positions covered formation testing
interpretation and answer product analyst in China.
Hadrien Dumont is a Reservoir
Domain Champion with
Schlumberger, based in Houston.
Previous positions held in
Schlumberger include Field Engineer
in Norway, Kazakhstan and Malaysia and Reservoir
Domain Champion in Egypt, Sudan, Syria, Indonesia
and United States of America.
David Fernando Diaz works with
Schlumberger supporting deep water
Gulf of Mexico customers. He holds
a degree in Electronics (1995) and a
Master of Business Administration
(2001). He started his career as Wireline field
engineer in 1996, and since then held multiple
positions in operations, support and management
mainly for Schlumberger wireline formation
evaluation services but also with the data and
consulting services.
Dr. Oliver C. Mullins is a Science
Advisor to senior management in
Schlumberger. He is the primary
originator of Downhole Fluid Analysis
(DFA) for formation evaluation. His
current interests involve use of DFA
SPWLA 55th
Annual Logging Symposium, May 18-22, 2014
14
and asphaltenes science for reservoir evaluation. He
has won several awards including the SPE
Distinguished Membership Award and the SPWLA
Distinguished Technical Achievement Award. He
authored the book The Physics of Reservoir Fluids;
Discovery through Downhole Fluid Analysis, which
won two Awards of Excellence. Dr. Mullins also
leads an active research group in petroleum science.
He has co-edited 3 books and coauthored 9 chapters
on asphaltenes. He has coauthored 210 publications
with 3900 literature citations. He has coinvented 85
allowed US patents. He is Editor of Petrophysics,
Fellow of two professional societies and is Adjunct
Professor of Petroleum Engineering at Texas A&M
University. His hobbies include skiing and biking.