Flow Scanner

Production logging
in multiphase
horizontal wells
Applications Multiphase fluid dynamics Flow regime in near-vertical well.
I Multiphase flow profiling In vertical wells and wells with devi-
in nonvertical wells ation less than 20°, oil and water are Velocity
I Identification of fluid and gas mixed across the entire wellbore, with
entries in multiphase well or oil, the lighter phase, increasing on the
liquid in gas wells upper side of the well. The velocity pro-
file is smooth, and the water holdup
I Detection of fluid recirculation
profile varies gradually across the pipe.
I Stand-alone, real-time, three- Averaged measurements across the Top Bottom
phase flow interpretation wellbore are adequate to determine the
velocity and holdup with this type of Holdup
1
Benefits flow structure.
I Unambiguous flow profiling Once deviation exceeds 20°, however,
in nonvertical wells regard- the center measurements of conven-
less of phase mixing or tional production logging tools are usu-
recirculation ally inadequate for multiphase flow 0
profiling. Top Bottom
I More accurate flow measure-
For wells with deviation between 20°
ments than possible with con- Water Oil
and 85°, some portions of the wellbore
ventional logging tools in highly
have monophasic flow, but the overall
deviated and horizontal wells
flow structure is complex. Water, the
I Three-phase flow rates com- Flow regime in deviated well.
heaviest phase, segregates to the bottom
puted in real time using dedi- of the pipe, and the mixing layer is on
cated algorithms the upper side of the hole with dispersed
bubbles of oil.
Features Water is frequently recirculated at low
I All sensor measurements flow rates, and the water velocity on the
simultaneous and at the lower side of the hole can be negative in
same depth some areas. At high flow rates, differen-
tial acceleration of phases caused by
I Combinable with PS Platform*
the shear forces between the different
and other cased hole logging Velocity Holdup
fluids can lead to instabilities in the 1
tools
flow structure. This flow structure has
I Short length for running in large gradients in the velocity and
wells with high dogleg severity holdup profiles.
I Direct, localized measure- Oil and water flows in wells with 0
ments of phase velocities and deviations between 85° and 95° are pre- 0
Top Bottom Top Bottom
calculation of a multiphase dominantly stratified. Water flows at
velocity profile the bottom with oil on the top. Even Water Oil
I Full three-phase holdup for flow rates as high as 20,000 B/D in a
answer from the same depth 5-in. [127-mm] liner, there is little mixing.
At low flow rates, the flow has a strong Flow regime in near-horizontal well.
I Scanning sensors across the
dependence on well deviation.
vertical axis for more accurate
When gas is also present, depending
detection of phase interfaces
on the well deviation, as many as six
I Measurement of mixed and major flow regimes can be encountered.
segregated flow regimes For a constant flow rate, the holdup
I Independent measurement and velocity profile of each phase vary
of gas velocity in multiphase with the well deviation.
horizontal wells Biphasic experiments carried out in
Velocity Holdup
I Detection of heavy phase a controlled flow loop with equal flow 1
recirculation downhole rates for oil and water show the dra-
matic effects of borehole deviation
I Software optimization and
on flow behavior.
real-time display of data from
all 19 sensors 0
I Caliper and relative-bearing Top Bottom Top Bottom
measurements for continuous
Water Oil
sensor location
 Flow loop experiment with equal flow rates for oil and water.

Relative speed

Oil
6,000

Water

Oil
Total
flow rate 1,500
(B/D)
Water

Oil

600

Water

89° 90° 91°

Deviation from vertical

At 90° the velocities and holdups of the oil because of its higher fluid density. influence the flow profile. Logging prob-
oil and water are nearly equal. Because The water holdup now decreases while lems typically occur when conventional
oil is more viscous than water, it has a the oil holdup increases. tools run in deviated wells encounter
slightly lower velocity. The oil holdup is top-side bubbly flow, heavy phase recir-
slightly higher than the water holdup. Why conventional production logging tech- culation, or stratified layers traveling at
As soon as the borehole deviates nology is inadequate in nonvertical wells different speeds.
slightly from 90°, the oil and water flow Using production logging to accurately Flow loop studies have also revealed
at different velocities. At high flow rates determine the inflow of oil, gas, and the ineffectiveness of conventional log-
the dependence on borehole deviation water phases is fundamental to devel- ging tools in multiphase flows. Center
is smaller because the increasing shear oping optimum production strategies measurements made by such tools are
frictional forces against the wall and and designing remedial workovers. inadequate for describing complex flow
interface dominate. But in highly deviated wells conven- because the most important information
At deviation lower than 90° (uphill), tional production logging tools deliver is located along the vertical diameter of
water, the heavier phase, slows down, less-than-optimal results because they the wellbore. Conventional tools have
and oil velocity increases. The water were developed for vertical or near- sensors spread out over long distances
holdup increases while the oil holdup vertical wells. in the wellbore, making measurement
decreases. Any gas present would start Downhole flow regimes in deviated of complex flow regimes even more
to slug. boreholes can be complex and can difficult.
At well deviation above 90° (down- include stratification, misting, and recir-
hill), flow is still predominantly strati- culation. Segregation, small changes in
fied. The water flows much faster than well inclination, and the flow regime
The solution: Flow Scanner system The Flow Scanner tool uses a maneuverable arm to deploy sensors along the vertical axis of nonvertical
The Flow Scanner* horizontal and wells to obtain velocity and holdup measurements in mixed and segregated flow regimes.
deviated well production logging system
was developed especially for highly
deviated and horizontal to near-
horizontal wells.
On one side of the tool’s retract-
able arm are four miniature spinners
designed to measure the well fluid-
velocity profile. On the other side are
arrays of five electrical and five optical
probes for measuring localized water
and gas holdups, respectively. Addition-
ally, a fifth miniature spinner and a
sixth pair of electrical and optical
probes on the tool body measure flow
properties on the low side of the well.
All sensor measurements are made at
the same depth simultaneously.
The Flow Scanner system is run
eccentered, lying on the low side of the
well with its arm deployed across the
vertical diameter of the wellbore. The
arm is extended to a length equal to
the diameter of the production tubu-
lars, so it serves as a caliper, providing
the area measurements needed to
calculate flow rates.
The tool has a small outside diameter
(OD) of 111⁄16 in.[42.9 mm], and it can be
run in holes ranging from 27⁄8 in. to 9 in.
[73.0 to 228.6 mm] using coiled tubing,
wireline, or the MaxTRAC* well tractor
system. Its short 16-ft [4.9-m] length
makes it ideal for wells with high dog-
A conventional spinner measures flow in the center of the wellbore, regardless of the flow profile,
leg severity. When an even shorter tool- whereas the Flow Scanner spinners measure velocities at five different points across the vertical
string is desired, the 4-ft [1.2-m] axis of the wellbore. The average velocity measurement of the conventional spinner would not account
hydraulic section used for scanning for the negative velocity measured here by the bottom spinner of the Flow Scanner tool.
and closing the tool can be removed.
The system operates in temperatures
to 302°F [150°C] and at pressures to
15,000 psi [103,425 kPa].
The Flow Scanner system is com-
binable with the PS Platform system
and other cased hole logging tools.

Multiphase velocity profiling

Because the Flow Scanner tool meas-
ures the velocity profile along the vertical
diameter of the wellbore, it can meas-
ure velocity variations that cannot be
detected using a single, centered spinner.
It provides measurements of mixed and
segregated flow regimes, including
direct independent measurement of gas
velocity in a multiphase horizontal
well. The Flow Scanner tool even
detects water recirculation downhole.
 Each of the five miniature spinners
On the basis of the fluid optical refractive index, GHOST probes make a binary distinction between gas
makes a direct, localized measurement and liquids.
of the velocity of the fluid passing
through it, enabling calculation of a
multiphase velocity profile.

Distinguishing hydrocarbons from water

The Flow Scanner system detects
water by using six low-frequency probes
that measure fluid impedance. Because
water conducts electric current, whereas
oil and gas do not, a threshold is set
that allows the tool to distinguish oil
and gas from water.
Each probe generates a binary signal
when oil or gas bubbles in a water-
continuous phase, or droplets of water
in a hydrocarbon-continuous phase,
touch the probe’s tip. Water holdup is
determined by the fraction of time a
probe’s tip is conducting, and the water Real-time flow rate and phase distribution data are continuously optimized and displayed on the
holdup profile accurately represents Flow Scanner system monitor.
the flow regime in the wellbore.
This methodology enables a local Surface Surface
water holdup measurement, independent
of fluid properties, without any need for
calibrations. Conventional tools, on the
other hand, require accurate calibration
in oil and water. Furthermore the bubble 90° 88°
count measurement—the log that rep-
resents the number of nonconducting
events detected during a monitoring Surface Surface
interval—can be used to locate fluid
entries. Conventional tools also lack
the accuracy to do this.

Distinguishing gas from liquids 92° 45°

Conventional low-frequency probes
can only distinguish water from hydro-
carbons, but the Flow Scanner system
is also equipped with optical probes Together, the optical and electrical In the spinner view, five rectangles
for gas detection. probes deliver a full three-phase holdup are plotted with lengths proportional
Its six GHOST* Gas Holdup Optical answer from the same depth interval. to the rotational velocities of the corre-
Sensor Tools are sensitive to the fluid sponding spinners. Each rectangle is
optical refractive index. Typically gas Flow Scanner monitor box divided into color-coded sections with
has an index near 1, water near 1.35, Flow Scanner software optimizes and widths proportional to the three phase
and crude oil near 1.5. Because oil and displays the data sent uphole from the holdups seen by the electrical and opti-
water have very similar fluid indices, spinners and probes. Two views are cal probes.
the optical probes are used to distin- constantly updated with real-time In the cross-sectional view, each
guish gas from liquid. acquisition data. layer is color coded to represent the
The gas bubble count can also be One view shows relative fluid veloci- phase with the highest holdup seen by
obtained from the raw data and used to ties measured by the spinner array, while the probes. The holdup values of the
locate first gas entries. Optical probes the other shows phase distribution across two remaining phases are represented
allow a local gas holdup measurement the pipe section. For both views, the by proportionate numbers and sizes of
without requiring calibration because pipe is sliced horizontally into the five bubbles. The relative positions of the
their signals are binary. layers associated with the different sensors are also shown, with circles for
combinations of spinner, electrical-probe, the spinners and dots for the probes.
and optical-probe measurements.
Case study: Gulf of Suez of the water and some oil were produced Case study: North Sea
Aging reservoirs in the Gulf of Suez from perforations at X390 ft. The two The Flow Scanner system was run in
produce viscous oils at high water cuts perforations above X390 ft were produc- a North Sea well on coiled tubing. The
through deviated to horizontal comple- ing clean oil, and more than half of the well was producing 9,800 BOPD, with
tions. Conventional production logging oil was flowing into the top perforation. 20% water cut and no gas, through a
tools often have difficulty defining the Conventional production logging sen- 41⁄2-in. [114-mm] liner. Maximum devia-
complicated flow regimes and identify- sors could not detect oil entering the top tion over the 2,300-ft [700-m] interval
ing areas for water shutoff to maximize perforations because the spinner was is 93°.
oil recovery as a field nears its eco- affected by water recirculation, and the In the flow profile shown in Track 1
nomic limit. resolution of the gradiomanometer was both oil and water were produced from
One well with an inclination of 37° was too low for it resolve oil contributions. the lowest perforations in the well, but
producing with gas lift through six open The conventional survey erroneously the major inflow of oil was at X680 m.
intervals. Production was 2,058 B/D with attributed 90% of the oil production Production increased significantly
97% water cut. When a conventional to the lower perforations. closer to the heel of the well.
production logging survey was unable On the basis of the Flow Scanner The holdup profile in Track 2 shows
to evaluate individual interval contribu- results, a workover operation was the effect deviation has in horizontal
tions or identify sources of water pro- planned to optimize the oil production. wells. Holdup varies greatly when flow
duction, the Flow Scanner tool was After cross-referencing the log results rates are low, and it lessens as flow
deployed on wireline. with geologic information on the loca- rate increases, eventually reaching a
The figure compares logs from the tion of a sealing layer of shale, the point at which deviation has almost no
Flow Scanner and conventional pro- operator set a plug at X400 ft to isolate effect. This proves the flow-loop tests
duction logging surveys. The Flow the majority of the high water-cut are representative of actual conditions
Scanner flow profile shows that approx- zones in the bottom of the well. downhole.
imately 25% of the oil and 85% of the The resulting production of 556 BOPD
water were being produced from perfo- and 2,532 BWPD represented an 800%
rations below X400 ft. The remainder increase in oil production, and payback
was accomplished in less than a week.

The Flow Scanner system identified and quantified zonal oil and water production in this well in the Gulf of Suez after conventional
production logging had failed. A workover operation led to an 800% increase in oil production.

Conventional PL Flow Scanner Conventional PL Flow Scanner Conventional PL Flow Scanner

Depth, Fullbore Spinner Gradiomanometer Flow Profile Flow Profile Well
ft Velocity Fluid Density Sketch
Velocity Fluid Density
Water Flow Water Flow
0 ft/min 40 Velocity Image 0.9 g/cm3 1.2 Water-Holdup Image
Spinner Stations Density Stations
Oil Flow Oil Flow
0 rps 3 –40 ft/min 40 0.9 g/cm3 1.2 0.92 1.0

X350

X400
 The Flow Scanner system demonstrated in this North Sea well that the effect of deviation on holdup
decreases as flow rates increase.

YY60

True
Vertical (m) Water Oil
Depth

YZ40

100

Flow (m3/h ) Water Oil

Profile

MD
1 : 4000 Perforation
m X000 X100 X200 X300 X400 X500 X600 X700 X800

Case study: Middle East

This Middle East well was producing 3,300 BOPD with 0% water cut. Holdup measurements show water
A client in the Middle East wanted to to 100 ft below the surface, and the velocity image shows that the water is recirculating.
test the Flow Scanner system in a well
considered to be single phase. The 52°
deviated well was producing 3,300 BOPD,
with no water. The Flow Scanner sys- PS Platform
Deviation
–5,000.0000
–21.0000
–5.0000
tem was run on wireline and recorded 40 (°) 60 –2.0000
–1.0000
–0.5000
the field log shown in the figure. Cable
–0.4000
–0.3000
Velocity –0.2000
The relative bearing measurement Memorized –0.1500
–0.1000
–100 (ft/min) 100
(purple) in Track 1 shows that the tool –0.0500
–0.0100
0.0100
kept its sensors deployed across the ver- 0.0500
0.1000
0.1500 Well
tical axis with only slight movement and Calibrated
Caliper
0.2000
0.3000
Pressure
0.4000
remained within 10° throughout the pass. 5 (in.) 7 0.5000
1.0000
0 (psia) 5,000

Track 2 shows the holdup of each 2.0000

–5,000.0000

5.0000
–1.0000

0.0000

1.0000

phase in the well. It clearly shows FSIT RB

Mixture Velocity Image (full range)
Water
Flow Rate Oil Flow Rate Gamma Ray
Well
Temperature

water to 100 ft below the surface. –20 (°) 20 Total Holdup (m/s) –1,000 (B/D) 4,000 0 (B/D) 5,000 0 100 250 (°F) 275

Track 3 is a velocity image. Negative

velocity (recirculation) is shown in
yellow, then orange, and red as it
increases; increasing positive velocity
(production) is shown in blue, then green, X000

and dark green. Oil is being produced

in the middle and on the high side of
the well, while water is recirculating
on the low side of the well (left).
Recirculation could be seen to 100 ft
below the surface.
Tracks 4 and 5 represent the water
flow rate (negative) and the oil flow X100

rate (positive) calculated using the

default pitches for all five spinners.
Tracks 6 and 7 show the gamma
ray, pressure, and temperature curves
recorded with the PS Platform basic
measurements sonde.
Flow Scanner Specifications
OD (in. [mm]) 1.668 [42.9]
Length† (ft [m]) 16.0 [4.9]
Weight (lbm [kg]) 108 [49]
Temperature (°F [°C]) 302 [150]
Pressure (psi [kPa]) 15,000 [103,425]
Corrosion resistance NACE Standard MR0175
Borehole coverage 90% in 6-in. ID
Three-phase holdup accuracy ±10%
Velocity accuracy ±10%
Hole size (in. [mm]) 2.875 to 9 [73.0 to 228.6]
Min. restriction (in. [mm]) 1.813 [46.0]
† Flow Scanner tool only. Basic measurement sonde and head add 10.2 ft [3.1 m]. An eccentralizer and swivel are also recommended in
deviated wells.

www.slb.com/oilfield
06-PR-039 August 2006
*Mark of Schlumberger
Copyright © 2006 Schlumberger. All rights reserved.
Produced by Schlumberger Marketing Communications