downhole viscosity measurement: revealing reservoir...

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

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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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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

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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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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

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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



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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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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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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).

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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

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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.

downhole viscosity measurement: revealing reservoir...

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