registro de pozoz

1. 44 Oilfield Review
Steve Bamforth
BP Exploration Operating Co. Ltd.
Poole, England
Christian Besson
Ken Stephenson
Colin Whittaker
Cambridge, England
George Brown
BP Exploration Operating Co. Ltd.
Sunbury on Thames, England
Gérard Catala
Gilles Rouault
Bernard Théron
Clamart, France
Gilbert Conort
Montrouge, France
Chris Lenn
Dubai, United Arab Emirates
Brad Roscoe
Ridgefield, Connecticut, USA
For help in preparation of this article, thanks to Ashok
Belani, Schlumberger Wireline & Testing, Montrouge,
France; John Ferguson, Schlumberger Cambridge
Research, Cambridge, England; Yves Manin,
Schlumberger Riboud Product Center, Clamart, France;
Jean-Rémy Olesen, Beijing, China; DeWayne Schnorr,
Anchorage, Alaska, USA; Antonio Jorge Torre, Technical
Editing Services, Houston, Texas, USA; and Amal
Vittachi, GeoQuest, Dallas, Texas.
BorFlo, CPLT (Combinable Production Logging Tool),
FloView, FloView Plus, PLT (Production Logging Tool),
PL Flagship, PVL (Phase Velocity Log), RST (Reservoir
Saturation Tool), TDT (Thermal Decay Time) and
WFL (Water Flow Log) are marks of Schlumberger.
Revitalizing Production Logging
Thousands of high-angle and
horizontal wells have been
drilled in the last ten years.
As a result, there are many
mature fields with complex
well production problems.
Today, new technology and
better understanding of fluid
flow in wellbores have
revived production logging
methods for all types of wells.

2. Winter 1996 45
For decades, production logs have been
used in new wells to optimize ultimate
recovery and to help avoid potential pro-
duction problems. In older wells, these logs
aid in diagnosing declining production and
planning remedial work.1
From the outset, production logging (PL)
has been used to determine the dynamic pat-
terns of flow rates of water, oil and gas under
stable producing or injecting conditions by
answering the following questions: How
much of the well is flowing? Which zones are
producing oil, water and gas? How much of
each type of fluid is flowing from each zone?
Ideally, PL techniques should identify each
fluid, measure the volume fraction of each
fluid in the pipe—called the holdup—and
its velocity, and from these compute flow
rates.2 Traditional PL measurements use tur-
bine flowmeters called spinners for velocity,
gradiomanometers for density, capacitance
for holdup, manometers for pressure and
thermometers for temperature. Of these five
measurements, only velocity and density
tend to be used in traditional quantitative
PL analysis.
The reliability of the data generated by
traditional PL logging depends almost
exclusively on the type of well being
logged. In vertical wells with high flow
rates—usually from 200 to 5000 B/D [30 to
800 m3/d], depending on the tool used and
the pipe diameter—these PL measurements
and their analysis usually produce reliable
results. However, in some wells, phenom-
ena such as flow behind casing or inter-
zone flow make traditional PL difficult.
The upsurge in deviated and horizontal
wells creates boreholes with very different
fluid flow characteristics from vertical wells,
adding further complexity to multiphase
flow and radically changing the physics and
technology of fluid-flow measurement
(above). In gas-and-liquid or oil-and-water
flow, the lighter phase moves rapidly along
the high side of the borehole, establishing a
circulating current that often causes a back-
flow along the lower side (see “Fluid Flow
Fundamentals,” page 61).
Depending on the borehole deviation, the
velocity and holdup of the different phases
can change dramatically for any given flow
rate. In these circumstances, traditional PL
measurements may become unreliable.3
This article looks at how new techniques are
helping to shed light on flow in complex
vertical wells, and to deliver PL measure-
ments in deviated and horizontal wells.
,,,,,
,,,,,
,,,,,
,
,,,,,
Stagnant gas Failed external
casing packer
Fault
Formation
instability
Oil layer
Cuttings Fractures
Water
Gas
,,,
,,
,,,
ssThe challenges facing production log-
ging in horizontal wells. Trapped fluids
can directly affect production and influ-
ence the data from a production log, espe-
cially sensors such as spinners and capac-
itance tools. Because horizontal wells
inevitably have doglegs and undulations,
stagnant water may lie either inside or out-
side the casing in low areas at the bottom
of the well; stagnant gas may accumulate
on the high side of drainhole undulations.
These nonflowing fluids distort measure-
ments. Changes in the flowing cross-sec-
tional area have a direct impact on spin-
ner response (inset, left). Horizontal wells
are frequently completed uncemented,
using prepacked screens or slotted liners
with external casing packers (ECPs). An
ECP that fails to set properly or formation
collapse create volume changes that
affect flow velocities. Faults, fractures and
formation instabilities may cause fluid
crossflow. Cuttings on the low side of the
borehole may alter fluid velocities and
result in erroneous readings.
1. Wade RT, Cantrell RC, Poupon A and Moulin J: “Pro-
duction Logging (The Key to Optimum Well Perfor-
mance,” Journal of Petroleum Technology 17 (Febru-
ary 1965): 137-144.
2. For an authoritative treatment of multiphase flow: Hill
AD: ”Production Logging-Theoretical and Interpreta-
tive Elements,” SPE Monograph 14, 1990.
3. Brown G: ”Using Production-Log Data From Horizon-
tal Wells,” Transactions of the SPWLA 36th Annual
Logging Symposium, Paris, June 26-29, 1995, paper SS.

3. 46 Oilfield Review
When to Run Production Logs
Generally, PL has two important applica-
tions: measuring well performance with
respect to reservoir dynamics and analyzing
mechanical problems in the borehole.
Although decisions to run production logs
usually depend on specific reservoir eco-
nomics, there are general guidelines.
First, PL may be used in new wells to eval-
uate initial production and verify the
integrity of the completion—for example,
indicating where there is flow behind cas-
ing. When initial performance does not
meet expectations, information from PL may
often point to remedial work to optimize
production and suggest different completion
techniques for future wells.
A special use of PL in horizontal, high-rate
wells is to verify friction-induced production
loss in long drainholes. This friction loss
sometimes negates any extra productivity
expected from the long drainhole, and a
better choice would be to drill multiple,
shorter lateral sections in a stacked or fan-
shaped pattern.4
Second, PL should be considered for any
well that shows sudden decreases in pro-
duction or increases in gas/oil ratio (GOR)
or water cut.
Third, just as a yearly checkup by a physi-
cian is prudent, PL may be used periodically
to detect problems such as water or gas con-
ing, or fingering before extensive production
loss occurs. This is particularly important for
dump-flood wells, where PL is the only
monitoring method.5
Fourth, injection wells may be initially
analyzed and then monitored with PL.
Knowledge of where injected fluids are
going is critical for avoiding undesired
flooding that leads to serious problems such
as casing-annulus crossflow, the creation of
unswept and trapped hydrocarbons, and
water-wet damaged formations.
1:200 m
X50
X25
Radius of Bit
0 10
Openhole Sw
1993
100 p.u. 0
Openhole Porosity
50 p.u. 0
Openhole Porosity
50 p.u. 0
Downhole Flow Rate
0 B/D 10000
RST Oil
1996
1996
100 p.u. 0
Openhole Sw 1993
50 p.u. 0
Openhole Fluid Volume
1996
50 p.u. 0
RST Fluid Volume
GR (C.H.)-GR (O.H.)
1 0 0
Borehole Water
Borehole Oil
Casing Wall
Assumed Cement
Sheath
Formation
Perforated Zone
Nonmovable Oil (O.H.)
Water
Shale 1
Shale 2
Feldspar
Quartz
Calcite
RST Oil 1996
Water
Oil
Gas
Scales
4
Zone
3
2
1
ssOpenhole CPLT-RST evaluation from South China Sea. Track 1 (left) contains a well
sketch with casing (black) and a cemented casing-formation annulus (gray hatching).
Uranium scale was indicated by the difference in natural gamma ray activity between
the openhole and most recent cased-hole gamma ray survey. Track 2 contains the open-
hole log and the latest RST water saturation analysis. Track 3 shows the production logs
and static-fluid volume analysis in the formation. The top of Zone 3 at X41 and the top
half of Zone 2 at X47 still shows some unproduced oil. Zones 1 and 4 are completely
depleted. The production logs shows most of the water production coming from the top of
Zone 2 at X46 m.

4. Winter 1996 47
The ability to carry out downhole PL mea-
surements in a stabilized well under
dynamic conditions is the key to successful
production management. The resulting
downhole flow-rate determination may be
compared with stabilized surface flow rates.
This quantitative comparison between
downhole and surface flow rates allows
detection of any surface-to-downhole dis-
crepancies caused by such factors as tubing
leaks, thief zones, unwanted fluid entries or
other hydraulic malfunctions.
Production Logging in Vertical Wells
Increasingly, operators incorporate PL into
their reservoir monitoring programs. Today,
this often includes cased-hole saturation
logging techniques—such as thermal-neu-
tron decay time or carbon-oxygen measure-
ments—run in combination with traditional
PL tools to provide an enhanced under-
standing of reservoir dynamics.6
The RST Reservoir Saturation Tool can be
used to make a snapshot of reservoir satura-
tion. Repeating these measurements over
time helps monitor changes in reservoir sat-
uration. But the dynamic description of
flow conditions obtained from production
log profiles is absolutely necessary to
unravel complex commingled production
in a many wells.
For example, to gain a clear picture of pro-
duction dynamics in a declining reservoir, the
CPLT Combinable Production Logging Tool
log and the RST technique were used in com-
bination in a reservoir located in the Pearl
River Mouth basin in the South China Sea.
The reservoir, a sand-shale sequence, was
producing from four commingled sand-
stone formations, and the operator needed
to understand current reservoir production
on a layer-by-layer basis. The CPLT-RST
reservoir monitoring suite was deployed in
a well located at the top of the reservoir
(previous page). Openhole well evalua-
tions, with the latest hydrocarbon volume
from RST C/O monitoring, showed the
changes in reservoir saturations.
The lowest zone had been completely
depleted, as had about half of the next
zone. A cased-hole versus openhole gamma
ray comparison revealed evidence of sub-
stantial scale buildup in the lowest perfo-
rated zones. This indicated that large vol-
umes of water had been produced from the
lower zones, and scale could potentially
plug perforations.
The production logs provided the key to
understanding what was happening in the
well. The flowmeter and gradiomanometer
profiles showed that there was only a little
fluid production, mostly water, coming from
the lowest perforations. About 60% of the
total water production came from the sec-
ond lowest set of perforations, and most of
that from just 2 m [6.5 ft] of the upper sec-
tion of perforations.
Surprisingly, the RST monitor log indicated
that water production was coming from a
fully oil-bearing part of the formation. It was
suspected that the water was coning up
from the bottom part of the zone, now com-
pletely depleted of hydrocarbons. Logs from
other wells, downdip in the reservoir, con-
firmed this conclusion. Reducing the draw-
down pressures may allow production of the
bypassed hydrocarbons, still contained in
this zone, to continue.
In the well’s second highest perforated
zone, the RST monitor logs showed a signif-
icant oil-water contact (OWC). The lowest
half of the zone was fully depleted, whereas
the upper half was untouched by produc-
tion. Unexpectedly, production log profiles
indicated greater hydrocarbon production
than water, perhaps because scale had
plugged the lower perforations in the
watered-out part of the zone. The upper per-
forations in this zone did not appear to be
plugged by scale, yet the production profiles
showed minimal contribution over the
entire interval. This result confirmed the
diagnosis from RST monitoring logs that the
upper formation layer had been swept of all
movable hydrocarbons.
Another example, this time in a vertical
well with a thief zone and borehole water
entry, occurred in India’s offshore Bombay
High field, operated by Indian Oil and Nat-
ural Gas Commission (ONGC). The reser-
voir was under waterflood, and the operator
needed to identify zones of water entry and
to determine whether flow was occurring
behind the casing. It was also suspected
that injection water had broken through
and was being produced from one of five
sets of perforations.
A WFL Water Flow Log tool was com-
bined with the PLT Production Logging Tool
log to distinguish between flow inside and
outside the casing (see “Fluid-Flow Logging
Using Time-of-Flight,” page 50). The down-
hole flow rates were complex. The top of
the lowest set of perforations, Zone 5, pro-
duced only small quantities of water. There
was a large increase in water flow coming
from the second lowest set of perforations.
A modest amount of oil, 400 BOPD
[63 m3/d], was also produced from this
zone. The middle set of perforations, Zone
3, also produced 1000 BWPD [160 m3/d]
with only a small amount of oil. The second
highest set of perforations showed no fluid
production (next page).
4. Hill D, Neme E, Ehlig-Economides C and Mollinedo
M: ”Reentry Drilling Gives New Life to Aging Fields,”
Oilfield Review 8, no. 3 (Autumn 1996): 4-17.
5. In dump-flood wells, water is produced from an
aquifer and injected into a producing formation in the
same well.
6. Albertin, I, Darling, H, Mahdavi, M, Plasek R, Cedeño
I, Hemingway J, Richter P, Markley M, Olesen J-R,
Roscoe B and Zeng W: “The Many Facets of Pulsed
Neutron Cased Hole Logging,” Oilfield Review 8,
no. 2 (Summer 1996): 28-41.
An essential input for RST-A C/O monitoring logging is
the oil holdup in the borehole. The PL gradiomanome-
ter provides this measurement.

5. 48 Oilfield Review
With the top set of perforations—Zone 1—
the picture changed dramatically. Here,
more than half of the production from the
four zones below disappeared into the for-
mation. Zone 1 was acting as a major thief
zone, consuming 120 BOPD [19 m3/d] and
about 2200 BWPD [350 m3/d] from the
well. This unusual crossflow, verified by
WFL results, indicates a pressure differential
between the two formation layers, which
was not present when the well was initially
put on production. The WFL survey also
indicated that there was no channeling
behind the casing.
Armed with this knowledge, the operator
had two choices for remediation—squeeze
the perforations in the lowest zones (3 to 5)
to prevent water production, or isolate
Zones 1 and 2 using a dual-completion
scheme, putting the long string on gas lift,
and allowing continued production of 400
BOPD [64 m3/d] from Zone 4.
Nonvertical Production Logging
Once a well substantially deviates from
vertical and multiphase flow becomes
complex, spinner tools often indicate only
reverse flow—especially when the spinner
is not centralized in the borehole, but lying
near the bottom where the reverse flow is
found (next page, right).7 Capacitance tools
may also measure the lower, denser phase
of the fluid giving misleading holdup data.
As the well’s angle increases to horizontal,
flow becomes entirely stratified, and the
averaged mixture velocity from a flowmeter
spinner alone is meaningless.
Other phenomena affect PL measurements
in deviated and horizontal wells. For exam-
ple stagnant fluids may confuse sensors;
fractures and faults may allow crossflow;
and failed external packers may introduce
variable flow regimes (see page 45).
Horizontal and many deviated wells are
often completed either open hole, with
uncemented slotted liners or with
prepacked screens.8 Such completions
introduce other special fluid-flow and pro-
duction problems that usually are not
encountered in vertical, cased wells—such
as flow restrictions due to the logging tool in
the pipe forcing fluids to channel through
the liner-formation annulus. Furthermore, a
0 12 24 36 48 60
0
300
600
900
1200
Countrate,cpsCountrate,cps
1500
0 12 24 36 48 60
0
10
20
30
40
50
GR
API
Measured Fluid
Velocity ft/min
1:200
0 60
0 125
X390
5
4
3
2
1
X380
X370
Measured Fluid
Density gm/cm3
0 125
Measured
Temperature
°F
WFL
Water Flow Rate
BWPD
243 245
Reconstructed
Fluid Velocity
ft/min
0 125
Reconstructed
Fluid Density
gm/cm3
0 125
Downhole
Flow Rate
B/D
Gas
Oil
Water
0.0 6000.0
0.0 6000.0
200
160
120
80
40
0
0 12 24 36 48 60
0 12 24 36 48 60
0
100
200
300
400
500
Time, sec
0 12 24 36 48 60
0
40
80
120
160
200
0 12 24 36 48 60
0
40
80
120
160
Time, sec
200 GR
Far
Near
GR
Far
Near
Zone
ssThief zone in vertical well. The PLT-WFL interpretation
analysis indicated that Zone 1 is removing more than
120 BOPD and 2200 BWPD from the well. Crossflow had
been set up by the injection and production schemes.
At X354, the WFL decay-time distributions showed a
flow rate over 2000 BWPD inside the casing (inset,
above right). At X393 m, the WFL decay-time distribu-
tions showed that no flow was detected (inset, right).

6. Winter 1996 49
special problem occurs near the uphole end
of a slotted liner. Here, annular fluids are
forced out of the annulus back into the liner
or casing, resulting in significant turbulence
that tends to mix the fluids. This turbulence
can encourage backflow to develop on the
low side of the hole, which can seriously
affect flowmeter readings.
In horizontal wells completed with con-
ventional cemented liners, flowmeter spin-
ner profiles look more like their vertical
counterparts, often showing smooth, distinct
evenly-separated profiles when recorded at
different speeds.9 However, cementing in
horizontal wells is usually not as successful
as in vertical wells because the liner is
decentralized within the borehole, often
leading to cement voids and channels with
accompanying annular production.
Other problems in horizontal completions
include acceleration of fluids due to gravity
when undulations in the well profile are suf-
ficiently large. If peaks of the flowmeter mea-
surements are taken as representative of the
full mixture velocity, the trend is an increase
in velocity where the well turns downward
and a decrease as the flow reaches the
trough of the undulation. Backflow always
appears to occur in inverted, undulating
wells where the heavy phase falls down the
low side of the drainhole. In many cases, the
heavy phase (usually water) simply circulates
in the sump and is not produced.
Delivering Data from Deviated Wells
Success in isolating crossflow problems in
the offshore Bombay well convinced the
operator to try a combined WFL-PLT
approach in a cased-hole, deviated well that
was producing oil, water and gas. The oper-
ator was unsure of the exact location of the
water entry zones and whether these could
be sealed off using cement squeezes to
reduce water cut.
Again, channeling behind casing was sus-
pected. This time, the WFL measurements
showed this, and confirmed the PLT measure-
ments in a difficult environment. The spinner
tool data below X050 indicated downflow,
the temperature gradient suggested possible
upward fluid movement and the gra-
diomanometer tool showed a single-phase
fluid below X050—a very confusing picture.
The spinner measurement was presumed
unreliable in this zone, as it had insufficient
resolution to measure low apparent flow.
The thermometer was affected by fluid
movement inside and outside the casing,
but could not differentiate between the two
flow regions. The WFL data helped resolve
the dilemma, by distinguishing between
flows inside and outside the casing (above
left). In this case, water was flowing outside
,,,,,,,,
,,,,
,,,,
,,,,
Water flow
Gas flow
ssBackflow as drain-
hole moves towards
vertical. In highly
deviated or horizon-
tal wells and at low
fluid velocities,
buoyancy forces
tend to segregate
fluids. The lighter
phase flows in the
upper part of the
pipe dragging
along with it some
of the heavier
phase. Sometimes
part of the heavier
phase moves down-
wards due to grav-
ity, causing a circu-
lation within the
pipe. Badly central-
ized flowmeters in
the lower portion of
the deviated pipe
will respond to this
downward flow.
7. In this article, the range of deviated wells will include
moderate to the so-called “high angle” 30° to 85°
from vertical; horizontal wells range from 85° to 95°.
8. Brown G, reference 3.
9. Spinner turn rates are calibrated by logging at different
cable speeds.
Countrate,cps
Flow Outside Pipe
Flow Inside Pipe
Countrate,cps
400
320
240
160
80
0
12 24 36 48 60
2200
880
440
0
1760
1320
Time, sec
12 24 36 48 60
Time, sec
Velocity = 8.5 ft/min
Rate = 439 BWPD
Background
Total count rate
Background
Total count rate
Velocity = 8.8 ft/min
Rate = 850 BWPD
ssDistinguishing between water flow inside
and outside casing. Time-of-flight gamma
ray time-decay distributions indicated
whether the flow is inside or outside the
casing. The lower graph shows the
response when water is flowing inside the
casing. The blue shaded area reflects the
final time-decay response to flowing water
after the background and standing water
signals have been removed. The blue area
had a sharply peaked response, which
indicated that the slug of activated water
flow occurred in a smooth cross-sectional
pipe area without dispersion. The top
graph indicates the magnitude and shape
of the time-decay response when flow is
outside casing. Here the time distribution
was much broader, reflecting slug disper-
sion as it flowed around the outside of cas-
ing. Lower total counting rates are due to
gamma ray attenuation in the casing.
(continued on page 52)

7. 50 Oilfield Review
Several years ago, the WFL Water Flow Log tech-
nique was introduced using the TDT-P Thermal
Decay Time tool to provide water-velocity data,
first in vertical wells, then later in deviated and
horizontal wells.1 Today, the RST Reservoir Satu-
ration Tool log provides water-velocity information
with more precision.2 A burst of fast neutrons from
the RST tool activates oxygen atoms in a small
region surrounding the neutron source in the tool.
This includes any oxygen in the water flowing in
the pipe. Oil does not contain oxygen and there-
fore is not affected. Activated oxygen atoms, in a
process like fluorescence, give off radiation, in the
form of gamma rays, radiating for a short time
after the neutron burst.
Moving water in the pipe will carry a cloud of
activated oxygen with it past the detectors in the
tool (above right). The time between the neutron
burst and the detection of the activated water cloud
will be a time-of-flight for the water flow in the
pipe, and is used to compute water velocity. The
half-life of the oxygen activation is only seven sec-
onds, so after a few minutes, the activation radia-
tion has subsided to an undetectable level, making
the measurement environmentally safe.
There are two detectors in the RST tool.The tool
can use a variable neutron burst width from 0.1 to
3 sec with delays from 3.5 to 20 sec to measure
water-flow rates from as low as 6 ft/min [1.8 m/min]
to as high as 500 ft/min [152 m/min]. The RST tool
may be inverted to measure downward water flow.
An additional gamma ray (GR) detector may be
incorporated in the logging tool string to measure
higher velocities.
The RST-WFL technique may be used to mea-
sure other parameters. The total activation count
rate is proportional to the volume of water acti-
vated by the neutron burst, and therefore is a mea-
sure of the water holdup in the pipe. The time pro-
file, or shape, of the activation count rate
distribution carries information about whether the
activated water is flowing near the tool in the bore-
hole or behind the casing pipe in the annulus.
Fluid-Flow Logging Using Time-of-Flight
Casing
Minitron
Water
Oil
Near count
rate
Far count
rate
GR count
rate
ssWFL Water Flow Log Measurements. A short burst of neutrons activates oxygen
in the surrounding water, and flowing water carries the activated cloud at the water
velocity. Source-detector distances and time-of-flight are used to determine the
water velocity.
0 10 20 30 40 50 60 70 80 90
Time, sec
Casing
Water
Oil
PVL Phase Velocity Log sonde
Oil-miscible marker RST tool
Near detector borehole sigma indicatorMarker signal
ss PVL Phase Velocity Log technique. A slug of oil-miscible marker fluid is injected
into the flowing oil phase, and is detected by the RST tool. The time-of-flight
between injection and slug detection along with the distance between the injector
tool and RST detector gives the oil velocity. The same process is used for water
phase-velocity measurements except a water-miscible marker compound is injected
into the heavier phase.

8. Winter 1996 51
For horizontal wells, fluid flows are stratified,
with the light phase moving rapidly in the upflow
sections of the well along the high side of the
borehole. Slight changes in borehole deviation
cause large changes in fluid holdup and the veloci-
ties of different phases, making it necessary to
know all fluid velocities. Spinners are usually not
applicable in stratified flow, and radioactive trac-
ers are useful useful only for water-velocity mea-
surements, because there are no oil-miscible
forms available. Radioactive tracers also have
strict procurement and safety issues.
The PVL Phase Velocity log also uses a time-of-
flight method to measure both oil and water veloc-
ities.3 This technique uses a chemical marker that
is injected into either the oil or water stream. The
time the marker takes to reach the detector is a
measure of fluid velocity (previous page, bottom).
The chemical marker contains a high concentra-
tion of the element gadolinium, which has a large
thermal neutron absorption cross section. The RST
tool senses the large increase in the borehole
absorption cross section caused by the passage of
the gadolinium slug (above).
A high concentration of gadolinium chloride
[GdCl3] in water is used as a water-miscible
marker. It has the high density and low viscosity
necessary for the water-phase measurements. For
the oil-phase measurements, a new, gadolinium-
rich compound, with low density and viscosity is
used. These markers are safe to handle, even in
concentrated form, and pose no environmental
threat when injected into borehole fluids.
Flow-loop experiments at Schlumberger Cam-
bridge Research, Cambridge, England have vali-
dated the PVL measurements under a large variety
of flow conditions. Both single-phase oil and water
measurements show excellent agreement between
PVL-measured and actual flow rates (above). Two-
phase measurements, using oil and water or gas
and water, demonstrate the ability to measure sep-
arately each phase in a segregated flow (right).
130
132
134
136
138
140
142
144
490
ft/min
12 ft/min
Time, sec
Boreholesigmaindicator
300
ft/min 200
ft/min
100
ft/min
50
ft/min
0 5 10 15 20 25 60 80 100 120
Raw Data
Filtered Data
ssTypical marker slug time-of-flight distributions for a variety of fluid-flow velocities.
500
Actual water velocity, ft/min
0
400
300
200
100
0
100 200 300 400 500
PVLmeasurements,ft/min
ssPVL water velocity measurements in the flow-loop.
Water velocity measurements made using the PVL
technique for horizontal stratified two-phase flow (oil
and water), where the water holdup was kept at 50%,
show good agreement with actual controlled flow
rates. The error bars are dominated by the sampling
frequency of the borehole absorption measurement.
200
100
0
200
100
0
200
100
0
200
100
0
200
100
0
Velocity,ft/min
Oil
Water
2300 BOPD
3000 BOPD
3800 BOPD
Deviation, degree
85 87 89 91 93
750 BOPD
1500 BOPD
ssTwo-phase velocity measurements in the
Schlumberger Cambridge Research flow loop. Oil and
water velocity measurements made using the PVL
technique in a laboratory flow loop with two-phase
flow where the water flow rate was maintained con-
stant at 1500 BWPD. The loop was tilted from 85 to
92 degrees and the water and oil velocities measured
for oil flow rates ranging from 750 to 3800 BOPD.
The results show that small deviations from horizon-
tal can cause large changes in the measured fluid
velocities.
1. Lenn C, Kimminau S and Young P: “Logging of Water
Mass Entry in Deviated Well Oil/Water Flows,” paper
SPE 26449, presented at the 68th SPE Annual Techni-
cal Conference and Exhibition, Houston, Texas, USA,
October 3-6, 1993.
2. Albertin et al, reference 6, main text.
3. Roscoe BA and Lenn C: ”Oil and Water-velocity Log-
ging in Horizontal Wells Using Chemical Markers,”
paper SPE 37153, presented the 1996 SPE Interna-
tional Conference on Horizontal Well Technology,
Calgary, Alberta, Canada, November 18-20, 1996.

9. 52 Oilfield Review
the casing below X050 m causing the tem-
perature to change faster than the local
geothermal gradient. Above X050 m, the
WFL data revealed flow inside the casing, in
good agreement with the production log-
ging interpretation (right).
The WFL interpretation helped pinpoint
the three-phase production to Zones 2 and
3. Only gas and oil enter the well from
Zone 1. The WFL data show that water, from
below Zone 5, flowed behind the casing.
With a clear understanding of the produc-
tion problems in the well, the operator
could choose between two remedial treat-
ments—eliminating all water production by
closing Zones 2 and 3, simultaneously cut-
ting potential oil production by a third; or
simply decreasing water cut by repairing the
cement below X050 m.
The next field example shows how a new
PL holdup and velocity imaging tool
helped determine the correct remedial
action for a well on the North Slope,
Alaska, USA operated by ARCO Alaska Inc.
and BP Exploration (next page, left).10
The 49° deviated well, was flowing at
1141 BOPD [181 m3/d] with 82% water cut
at surface and a GOR of 2583 ft3/bbl. Four
zones were originally perforated, and tradi-
tional PL interpretation based on density,
velocity and temperature indicated mixed
water and oil production in the lower three
zones, and gas in the top two. For example,
in the lowest perforated zone, the gra-
diomanometer showed a reduction in fluid
density, usually interpreted as first hydrocar-
bon entry. Based on traditional PL measure-
ments and interpretation, only this lowest
zone would be produced, and all upper
zones would have been plugged.
A completely different picture emerged
using the recently introduced FloView imag-
ing tool (see, “Advantages of Holdup and
Bubble Imaging in Production Logging,”
page 54). The FloView water holdup curve
remained at 100% in the lower zone. The
density drop measured by the traditional gra-
diomanometer probably occurred when the
tool moved from a dense sump fluid lying
below the lowest perforated zone into lighter
water produced from the first set of perfora-
tions. Next, the FloView holdup detected a
small hydrocarbon entry in Zone 2, and a
large entry in Zone 3, as seen in the FloView
holdup map.
Well Sketch
15 in. -15
Downhole Flow Rate
0 B/D 4000
WFL Water Rate
0 B/D 4000
1
X025
2
WFL GR red
-25 ft/min 100
WFL Far blue
-25 ft/min 100
WFL Near green
-25 ft/min 100
Fluid Vel
-25 ft/min 100
Theor.Dens
6.6 1.10
gm/cm3
Theor. Temp
235 240
°C
Theor. Pres
1010 1090
psi
Fluid density
0.6 1.10
gm/cm3
Temperature
235 240
°C
Pressure
1010 1090
psi
Matrix
Cement
Production
Perforations
Shale
Water
Oil
Gas
WFL Water Rates
3
X050
4
X075
5
Flow outside
Outsidevelocities
ssWater flow logs at different depths in a deviated well. Track 1 (left) shows a well sketch
and perforations at each zone. Track 2 shows WFL velocity results. The next three tracks
show PL density, temperature and pressure measurements. Results of flow model analysis
are shown in Track 6 (right). The reconstruction of PL measurements (dashed red) based
on the flow model analysis is shown along with the original (solid black) PL measure-
ments in Track 5. Three detectors were used by the WFL to cover a wide range of flows.
Water velocities inside the casing, derived from the near detector are shown as green cir-
cular tadpoles, while the far detector readings are shown in blue and the gamma ray
readings in red. The triangular-shaped tadpoles represent readings for flow outside the
casing. In this display, the 45° angle of the tadpole tails show an upflow in the well.
Downward flow would be indicated by tails pointing 45° downward.10.Vittachi A and North RJ: ”Application of a New
Radial Borehole Fluid Imaging Tool in Production
Logging Highly Deviated Wells,” paper SPE 36565,
presented at the SPE Annual Technical Conference
and Exhibition, Denver, Colorado, USA, October
6-9, 1996.

10. Winter 1996 53
In addition, the FloView bubble (or hydro-
carbon) velocity map pinpointed the first
significant hydrocarbon entry midway up
Zone 3. The caliper readings, shown as a
casing cross-section profile, supported the
idea that the gradiomanometer interpreta-
tion was adversely influenced by changes in
casing diameter between Zones 1 and 3. A
restriction in the casing at X900 ft caused an
increase in both spinner and FloView veloc-
ity measurements.
Just above X900 ft, between Zones 3 and
4, there was a reduction in average FloView
bubble velocity. The FloView images
showed a narrow band of hydrocarbon in
this section of the well—low water holdup
and higher bubble velocity throughout the
top section of the casing. This zone
appeared to have water backflow shown by
comparing an overlay of two passes of the
FloView velocity, one going up the well and
a second traveling downhole. A large sepa-
ration between the up and down passes was
seen in the region experiencing the water
backflow. The upgoing FloView pass read
higher hydrocarbon velocity than the down-
going pass. This occurred because water
was flowing backwards down the pipe, car-
rying hydrocarbon bubbles down with it
against the upward motion of the tool. This
abnormal separation in FloView velocities is
an easily recognized flag to spot reverse
flow in the well.
Farther up the well, the opposite occurred.
Starting at Zone 4, the upgoing FloView
pass had a lower hydrocarbon velocity than
the downgoing pass. This occurs because
hydrocarbon bubbles, carried by the
upward flowing water, were moving along
with the upward moving tool—a sign of sig-
nificant hydrocarbon entry in Zone 4.
The downhole flow rates and profiles com-
puted from the imaging measurements were
significantly different from those determined
using traditional PL measurements alone.
Flow rates calculated using data from this
new technique were within 8% of actual
production rates (above). Based on these
results, the recommendation to the operator
was to plug off all the zones except Zone 3,
the only significant oil producer.
The overlay techniques shown in this
example can be used as a qualitative
method of identifying zones of hydrocarbon
entry and water backflow.
FloView
Hydrcarb.
Velocity (down)
Oil
Water
Gas
Gradio Density
0.6 gm/cm3 1.1
Temperature
218 °F 223
0.5 v/v 1
FloView
Holdup
FloView
Holdup Map
Downhole Flow
Profile
0 10,000
B/D
Spinner Velocity
25 ft/min 375
0 ft/min 350
FloView
Velocity (up)
FloView
Velocity Map
0.6 1.0
v/v
0 350
ft/min1:600 ft
Perfs
Casing
GR
0 150
API
X800
X1000
X900
1
2
3
4
ssIdentifying fluid entry. The holdup map in Track 2 and the hydrocarbon velocity map
in Track 4, from an Alaskan well show the first hydrocarbon entry in Zone 3. The center
of each map track represents the high-side of the casing. The difference between the up
(dashed red) and down (solid red) passes of the FloView imaging tool in Track 3 indicates
backflow (shaded grey area where curves cross over) at X900, and hydrocarbon
production (unshaded crossover) in Zones 3 and 4.
4
Production, B/D
3
2
1
0 20001000 3000 4000
Conventional PL Results
4
Production, B/D
Zone
3
2
1
0 2000 4000
PL Results with FloView
Gas
Oil
Water
Gas
Oil
Water
1000 3000
Zone
ssComparing production logging tech-
niques. Downhole production from each
zone was measured using conventional
PL techniques and compared with those
from the new FloView imaging technique.
The new technique showed that only
Zone 3 had significant oil production.

11. 54 Oilfield Review
The 111⁄16-in. FloView production logging tool
makes four independent measurements of bore-
hole fluids, distributed in different quadrants of the
pipe cross section (right).
The self-centralized device uses matchstick-
sized, electrical probes to measure the resistivity
of the wellbore fluid—high for hydrocarbons and
low for water. The probes are located inside of
each of the tool’s four centralizer blades to protect
them from damage, and their azimuthal position
within the pipe cross section is measured.
The FloView imager may be run in up to 95⁄8-in.
casing. Each probe is sensitive to the local resis-
tivity of the fluid within the pipe and generates a
binary output when their sharp leading edges
impinge on droplets of oil or gas in a water-contin-
uous phase, or conversely, water in an oil-continu-
ous phase (next page, left). Assuming the fluids
are distinct and not in an emulsion form, and that
the bubble size is larger than the tip of the probe
(less than 1 mm), both water holdup and bubble
count measurements may be obtained from the
binary output of the probe.1
Water holdup is computed from the fraction of
the time that the probe is conducting, and bubble
count comes from the average frequency of the out-
put. In a water-continuous phase, an increasing
bubble count means an increasing hydrocarbon
velocity, and vice versa in an oil-continuous phase.
In biphasic fluid flow, the oil or gas holdup may be
obtained from a closure relationship with the water
holdup—the closure relation simply states that the
sum of the holdups of all the phases equals unity.
The probes cannot discriminate oil from gas.
Even in three-phase fluid flow, this device still
yields an accurate water holdup measurement.
Averaged local outputs for holdup and bubble
count are determined for each of the four individ-
ual probes. The outputs from each of these probes
are combined to map local stratified holdup.
In a typical two-phase environment, the FloView
tool has many advantages over the gradiomano-
meter (next page, right). Jetting of producing fluid
in front of perforated zones or changes in pipe
diameter because of scale or restrictions have a
venturi pressure effect on gradiomanometer
response. The gradiomanometer does not mea-
sure density directly, but measures the gravitation
pressure gradient with differential sensors over a
known vertical height difference. For this reason,
gradiomanometer measurements are more diffi-
cult in highly deviated wells and are impossible in
horizontal wells because the vertical separation
between sensor measure points is reduced and the
measurement loses resolution. Finally, if the flow
velocity is sufficiently high, friction will affect the
gradiomanometer response.
Advantages of Holdup and Bubble Imaging in Production Logging
ssFlow-imaging tool and holdup images. The FloView imaging tool has four probes, which map the local water
holdup in the borehole (inset above). FloView images show increasing water holdup as deviation decreases
and correlate well with flow loop photos.
Probe
Probe
Probe
FloView images
ConnectorCeramic
insulator
0
0.5
Water holdup
0.440.48
91º90º89º80º
0.580.71
Flow rate
1500 B/D
Deviation
from vertical
1
Conductive
tip
Probe holding
bracket
Casing
Flow loop photos
1. During most field tests, bubble sizes vary between 1
and 5 mm, within the requirements of the probes. Only
at high flow rates (in excess of 2 m/sec [6.5 ft/sec]) are
smaller bubble sizes experienced that might affect the
holdup and bubble-count measurements.

12. Winter 1996 55
Probe output
Conducting
Time
Not
conducting
Probe
Flow
Oil
Gas
ssPrinciple of local probe measurement. Oil and gas do not conduct electric
current, but water does. Water holdup is determined by the fraction of time
the probe tip is conducting. Bubble count is determined by counting the
nonconducting cycles.
Jetting,
venturi
effects
Gradio
Second
oil
entry
First oil
entry
Water
entry
FloView
holdup
FloView
bubble
count
Stagnant
water
Mud
Friction
effects
Third oil
entry
ssFloView tool and gradiomanometer comparison in two-phase flow. At the bottom
of the well (middle), there is frequently some mud and dense stagnant water. The
gradiomanometer (right) responds to density change, and will detect the density
decrease above the stagnant fluid, which in many cases might be mistaken for oil
entry. FloView probes do not respond to the water change since both water and
stagnant water are conductive. Therefore, the holdup (left) remains at 100% and
the bubble count stays at zero. The next zone is producing water, typically opposite
perforations. The gradiomanometer detects another density change, and as before,
this change may be misinterpreted as an oil entry, because the produced water is
invariably less dense than the stagnant water. Once again, FloView probes do not
respond to this water change since both waters are conductive. At the first oil entry
in the next zone, the outputs of the FloView probes will indicate less than 100%
water holdup, and the bubble count will start to increase. The gradiomanometer
density will also record the change, if enough oil enters, and the oil density is suffi-
ciently different from the produced water. As the tool passes across additional oil
entries, FloView water holdup will continue to decrease and the bubble count will
increase. The gradiomanometer will also register these oil entries with a decreasing
density, if the oil entries change the mixture density significantly.

13. 56 Oilfield Review
Horizontal Wells: The Flagship Project
During 1994, British Petroleum Exploration
Operating Co. Ltd. and Schlumberger Oil-
field Services established a joint initiative—
“The Flagship Project”—to develop new
techniques for the diagnosis and treatment
of high-angle and horizontal well produc-
tion problems.
The diagnosis part of this project involved
development of new PL tools. First, a novel
tool string incorporating sensors targeted at
the stratified flow regimes encountered in
horizontal and near-horizontal wells was
developed—combining the CPLT tool, an
extra gamma ray detector, the RST tool,
FloView Plus tool, fluid marker injector and
a total flow rate spinner tool (above).11 This
equipment is now being used in the North
Sea and the Middle East to make quantitative
flow-rate measurements of oil and water in
cemented and perforated liners, with a long-
term goal of being able to measure three-
phase flow in uncemented liners.
The first application of this tool string was
to resolve flow profiles and monitor move-
ment of OWCs in the Sherwood sandstone
reservoir, in the Wytch Farm field that strad-
dles the coastline of southern England. Using
extended-reach drilling technology, at least
ten onshore wells were drilled with stepouts
of up to 8000 m [26,248 ft] and having
reservoir sections of up to 2700 m [8858 ft].
The wells have electrically submersible
pumps (ESPs) and produce up to 20,000
BOPD [3178 m3/d]. To manage the field, BP
employs production logging on selected
wells to assess flow profiles with respect to
reservoir zones and to monitor the move-
ment of OWCs. This information is used to
determine future well trajectories, optimize
standoff from the OWC and target future
well intervention needs, such as to shut off
water and add secondary perforations.
GR RST
FloView tools
Bubble velocity
Water holdup
RST Reservoir Saturation Tool
Oil holdup
Gas indicator
FloView Plus tool
WFL Water Flow Log
Water velocity
Water holdup
Water flow-rate index
CPLT
CPLT Combinable
Production Logging Tool
Pressure and temperature
Fluid marker
injector
Spinner
Total flow rate
Gamma ray
detector
PVL Phase Velocity Log
Marker injection for oil
and/or water velocity
ssThe PL Flagship tool string. This composite string consists of the CPLT Combinable Production Logging Tool, an RST module with an
extra gamma ray tool, used for water flow logging and PVL Phase Velocity Logging, a FloView Plus fluid imaging tool, a fluid marker
injector tool used with the PVL, and a total flow rate spinner tool. The two imaging FloView tools are mounted with their probes aligned
for enhanced coverage of the borehole cross section.
Water holdup
Above 0.94
0.88 - 0.93
0.82 - 0.87
0.76 - 0.81
0.71 - 0.75
0.65 - 0.70
0.59 - 0.64
0.53 - 0.58
0.47 - 0.52
0.41 - 0.46
0.35 - 0.40
0.29 - 0.34
0.24 - 0.28
0.18 - 0.23
0.12 - 0.17
0.06 - 0.11
Below 0.5
Average holdup = 0.261
ssHoldup image from Wytch Farm 1F-18SP well. Multiple positions of the imaging probes
provide a detailed local holdup image. From this image, the local holdup profile is com-
bined with the different phase velocities to determine multiphase fluid-flow rates.
11. Lenn C, Bamforth S and Jariwala H: ”Flow Diagnosis
in an Extended Reach Well at the Wytch Farm Oil-
field Using a New Tool string Combination Incorpo-
rating Novel Production Technology,” paper SPE
36580, presented at the SPE Annual Technology Con-
ference and Exhibition, Denver, Colorado, USA,
October 6-9, 1996.
12. Roscoe B: ”Three-Phase Holdup Determination in
Horizontal Wells Using a Pulsed Neutron Source,”
paper SPE 37147, presented at the 1996 SPE Interna-
tional Conference on Horizontal Well Technology,
Calgary, Alberta, Canada, November 18-20, 1996.

14. Winter 1996 57
Three Wytch Farm wells were chosen to
evaluate the new Flagship tool string—two
with water cut and one a dry-oil producer.
The first water-cut well 1F-18SP was drilled
to a 4450 m [14,600 ft] total depth, with a
horizontal displacement of nearly 3800
m [12,468 ft]. Once the main drainhole was
drilled through the productive section, the
well trajectory was dropped to penetrate the
OWC. This permits future logging of the
OWC as it moves. The reservoir was perfo-
rated 33 m [106 ft] above the initial OWC,
giving an initial estimated productivity index
(PI) of 100 B/D/psi.
Production started at 15,000 B/D
[2384 m3/d] dry oil, declining after three
years to a rate of 13,000 B/D [2066 m3/d]
fluid with a 9 to 14% water cut at the time
of logging. This well was selected to test the
new tool string because it had the highest
water cut in the field, penetrated the OWC
and presented the best opportunity for
coiled tubing intervention.
Despite using a revolutionary tool string
for this trial, the logging objectives were typ-
ical of any PL job: To determine the source
of water production, identify the oil and
water profile in the well and assess each
zone’s contribution, and determine any
movement of the OWC in the reservoir.
Analysis of the PL data revealed that the
well was producing fluid along the entire
length of its perforated section. Water pro-
duction was occurring only in the lowest
perforations—in the toe of the well—possi-
bly due to coning in a zone of high vertical
permeability, rather than a general move-
ment of the OWC.
The RST-Sigma saturation monitor logs
showed that the OWC had moved up only
10.8 m [35 ft] from its original position. The
independent WFL velocity and the PVL
water-velocity measurements both showed
good agreement with the PL results. In addi-
tion, oil-velocity measurements were
obtained from the PVL tool.
Local probes on the FloView tool provided
holdup distribution images of the fluids,
confirming that the flow was stratified (previ-
ous page, bottom). In addition, RST-C/O
ratio and borehole salinity from the RST-
Sigma logs were used for holdup analysis
(see “Multiphase Holdup Measurements,”
right).12 All three methods—FloView
Images, C/O ratio, and borehole salinity—
provided similar results, confirming trends
or conclusions about holdup analysis. Flow
profiles were computed from the velocity
and holdup measurements for both oil and
water phases.
Multiphase holdup measurements are made with
the basic RST C/O measurement, which is usually
used to determine the volume of oil in the forma-
tion. The carbon and oxygen signals are generated
by fast neutron inelastic scattering, which leaves
these elements in high-energy excited states that
decay immediately by gamma ray emission.
Most carbon-oxygen excitations take place within
15 to 23 cm [6 to 9 in.] of the tool. This means all
C/O measurements are sensitive to the local ele-
mental concentrations, and therefore to the relative
amount of oil and water holdup in the borehole as
well as the saturations in the formation (above).
The RST-A tool has two detectors with one more
and one less sensitive to the borehole environ-
ment by virtue of their spacing from the source.
Gamma ray spectra from both detectors lead to
relative elemental carbon and oxygen yields,
which are used to solve simultaneously for the vol-
ume of formation oil and the borehole oil holdup.1
The RST C/O crossplot response and RST-A
inelastic near-to-far count rate ratios are used
together to determine multiphase fluid holdup.
The inelastic spectra give carbon-oxygen ratios and
detector count rates. The crossplot near detector
C/O ratio response is determined primarily by the
oil holdup in the borehole and the far detector C/O
response by the oil volume in the formation. The
near-to-far inelastic count rate ratio primarily
depends on the overall borehole density, which is
related to the borehole gas holdup.2 Two-phase (oil
and water) holdup is determined using the crossplot
C/O response, while both crossplot and count rate
ratios are used simultaneously for holdup determi-
nation in three-phase (oil, water and gas) solutions.
Multiphase Holdup Measurements
1. Roscoe B: ”Three-Phase Holdup Determination in
Horizontal Wells Using a Pulsed Neutron Source,”
paper SPE 37147, presented at the 1996 SPE Interna-
tional Conference on Horizontal Well Technology,
Calgary, Alberta, Canada, November 18-20, 1996.
2. An approach to measure borehole gas holdup with a
fullbore backscatter gamma ray density tool can be
found in: Kessler C and Frisch G: “New Fullbore Pro-
duction Logging Sensor Improves the Evaluation of
Production in Deviated and Horizontal Wells,” paper
SPE 29815, presented at the 1995 Middle East Oil
Technical Conference, Manama, Bahrain, March
11-14, 1995.
YG
= 0.00
YG
= 0.33
YG
= 0.67
YG
= 1.00
Gas Holdup Response
Casing
Counts
InelasticN/FratioFarC/Oratio
Energy
Porosity
Near C/O ratio
C/O Model Response
Inelastic Spectrum Gas
RST
Tool
Water
YG
YW
YO
YG
Borehole
oil
Borehole water
Formationoil
Formation
water
Carbon
Oxygen
Near and Far count rate
Near and Far C/O ratio
ssMultiphase holdup from RST tool. Inelastic spectra (left) lead to carbon-oxygen ratios and near-and-far
detector count rates. The crossplot of near and far C/O ratio responses are determined primarily by oil holdup
YO in the borehole (lower right plot) and oil volume in the formation. The near-to-far inelastic count rate ratio
(upper right plot) primarily depends on the overall borehole density which is related to the borehole gas
holdup, YG.

15. 58 Oilfield Review
The data acquisition capability of the tool
string allows most critical parameters to be
determined by alternative independent
methods—for example, C/O and imaging
holdup data, or WFL and PVL velocity data
supported by spinner measurements—
instilling greater confidence in the results.
The new tool string clearly identified all
the water entry points in the well, confirmed
that the downhole flow was stratified, and
proved that water and oil flow rates could
be accurately determined using the new
phase velocity and C/O-based holdup mea-
surements. The upper perforations were pro-
ducing oil. Oil flow rates derived from the
PVL velocity and C/O holdup, within 500
B/D [80 m3/d], were 12,500 B/D
[1986 m3/d]. The water-flow rates derived
from the PVL and WFL measurements,
within 500 B/D, were 3500 B/D [556 m3/d].
In the second water-cut well to be logged
with the PL Flagship tool string, water entry
was found to be not from the toe as before,
but from a nonsealing intersecting fault. The
logs showed that water was being drawn up
through the fault from the OWC.
In the third well—a dry-oil producer—the
PVL oil-velocity measurements were tested
against a fullbore spinner flowmeter in the
horizontal drainhole completed with sand
screens. The PVL data matched the spinner
velocity, which functioned effectively in
monophasic production.
Tying It All Together—Interpretation
Traditional PL interpretation for vertical
wells primarily uses density from the gra-
diomanometer to compute oil and water
holdup, and the averaged measured
flowmeter velocity from the spinner to com-
pute fluid-flow rates using the slip velocity
computed from a fluid model.13 Pressure,
temperature and other data are largely
ignored by conventional PL analysis.
However, such a limited approach is inad-
equate for most wells. By using all available
production logging data, more complete
answers may be delivered with greater confi-
dence. The BorFlo production logging ana-
lyzer is being introduced to do this (above
right). This single interpretation package uses
physical models based on fluid dynamics in
deviated and horizontal boreholes, relating
the physics of fluid flow to the parameters
measured by the PL tools (see “Interpreting
Multiphase Flow Measurements in Horizon-
tal Wells,” next page). With this interactive
PL interpretation tool, measurements may be
stacked, tool responses calibrated and flow-
rate solutions determined.
Multiple measurement of production
parameters—such as fluid velocities from
spinners, WFL and PVL logging runs, as well
as holdup measurements from imaging tools
and RST logs—enable delivery of optimized
solutions to the fluid-flow dynamics. Knowl-
edge of sensor responses allows the opti-
mization to be based on the confidence lev-
els of each logging measurement.
This forward-modeling program tests the
results of different flow conditions, based on
many iterations, to determine the most likely
downhole fluid-flow regime that is consis-
tent with all the borehole geometries, well-
bore environment, and observed production
logging and surface measurements.14
Fluid Velocity
Stacking
Calibrations
Blocking
Flow Rate
Solution
Final Results
Initialization
Tool
Incoherence
Tool
Incoherence
S
o
l
v
e
r
Flow Model
Tool Model
7800
7600
7700
Spin - rpm
Cable
Speed
Bot. Top Slope Intercept
7750 7700 .21 .02
7800 7750 .22 .03
7800
7600
7700
Flow Velocity Temp
Inputs
Data Editing
Depth Matching
Log Inputs Well and Fluid
Characteristics
7600
7700
7800
Calibrations
Reconstruction
Depth Matching
Report and Well Sketch
Gas
Oil
Water
Lower
perfs
Upper
perfs
ssBorFlo overview. The PL interpretation program allows the engineer to do log stacking,
calibrations and define well and fluid characteristics interactively. The interpretation
matches the PL measurements with those determined by a fluid-flow model based on dif-
ferent flow conditions occurring at each interval.
13. Slip velocity is the difference between the two-phase
average velocities. For discussion of traditional pro-
duction log interpretation: Hill AD, reference 2.
14. For example, the Duckler analytical model is used to
determine parameters of the gas/liquid flow regime,
and the volumetric model developed by Choquette
and Piers separates the oil/water regime. For more on
the development and use of the constrained solver
PL interpretation models such as PLGLOB: Torre J,
Roy MM, Suryanarayana G and Crossoaurd P: ”Go
with the Flow,” Middle East Well Evaluation Review
13 (1992): 26-37.

16. A new fluid dynamics-based interpretation model
called the Stratflo model has been developed to
compute oil-water flow rates from logging mea-
surements in high-angle and horizontal wells.1 The
model depends on basic flow equations, which, in
turn, depend on dynamic parameters such as fluid
velocities and holdup, and static parameters such
as well diameter, borehole deviation, and fluid
densities and viscosities. Frictional terms at the
casing wall are based on monophasic results
(right). At the phase interface a simple flat inter-
face frictional model is assumed. A correlation for
the frictional factor between the two phases has
been developed from flow-loop measurements.
The model is based on the principle that the
pressure variation ∆P along the axis of the well in
each phase is equal. In steady state, the pressure
variation in each phase has a hydrostatic compo-
nent, which depends on density and the borehole
deviation (the difference in height of the vertical
positions), and a frictional component, which can
be divided into two parts: the shear stress on the
wall for oil Tow and water Tww, and the shear stress
on the fluid interface Ti.
The steady-state model simply sets the pres-
sure in the oil ∆Po equal to the pressure drop in
the water ∆Pw, by defining a function
F = ∆Po – ∆Pw = 0.
In this model, the function F depends on dynamic
parameters such as flow rates and holdup, as
well as static parameters, such as flowing diam-
eter D, deviation angle, θ, fluid densities ρo and
ρw, and viscosities, µo and µw. For example, in
terms of the dynamic parameters Vw water veloc-
ity and Vo oil velocity and Yw water holdup, the
function can be expressed as
F(Vw, Vo, Yw) = 0.
This function is a nonlinear algebraic equation
and a function of three independent variables.
To use the model, readily-measured parameters
such as local holdup and velocity measurements
may be used for two of the necessary input
dynamic parameters. With the mass conservation
equations, which relate flow rates, velocities and
water holdup, the model can be solved for other
combinations of inputs, depending on available
data. Outputs are computed from the flow model
and mass-conservation equations using a root-
finding technique.
The flow model gives good results up to about
6000 B/D [953 m3/d] for each phase—the limit
where the simple flat interface starts to degener-
ate as the mixing layer grows. The model accu-
rately accounts for the variation in holdup at differ-
ent borehole angles and flow rates (right).
Interpreting Multiphase Flow Measurements in Horizontal Wells
θ
Tow
Tww
Vo
Vw
Ti
∆P in water = ∆P in oil
Pressure Drop
Wall friction (Tw)
Interfacial friction (Ti)
Gravity (ρ,devi)
∆P
∆P
∆hρo
ρw
ssStratified flow model. The flow model for two-
phase flow equates the pressure difference due to the
hydrostatic head (which depends on borehole devia-
tion angle θ), ∆h, and the wall, Tw, and interfacial, Ti,
friction components for each of the two fluids.
1.0
Waterholdup
Deviation, deg
87
0.8
0.6
0.4
0.2
0
88 89 90 91 92
Flow model
Flow model
Flow=800 B/D
Flow=7000 B/D
ssMeasured and predicted holdup variation. Holdup
was measured at different deviations and flow rates
in the Schlumberger Cambridge Research flow loop
and compared with results predicted by the stratified
flow model StratFlo. The results show the rapid vari-
ation in holdup with borehole deviation at low flow
rates (red curve), as well as the reduced holdup sen-
sitivity at a high flow rate (yellow curve). The results
are shown for a water cut of 50%.
1. Theron BE and Unwin T: ”Stratified Flow Model and
Interpretation in Horizontal Wells,” paper SPE 36560,
presented at the 1996 SPE Annual Technical Confer-
ence and Exhibition, Denver, Colorado, USA, October
6-9 1996.
Winter 1996 59

17. The Outlook
The ongoing development effort in under-
standing three-phase flow is delivering
results—including detailed gas holdup and
velocity measurements—that are reshaping
PL services. However, there is still an impor-
tant flow domain not adequately covered by
today’s technology—environments where
there is low water holdup and significant
drainhole deviation. Work is under way at
SCR to understand the complex fluid
dynamics, flow instabilities and phase mix-
ing in all regions. This experimentation
together with hydrodynamic modeling will
lead to better future understanding and
management of flow in the borehole (right).
Improved instrumentation and tool tech-
nology are also promising faster, more effi-
cient and lower-cost services—some using
slickline. Other applications will see per-
manent downhole sensors used for produc-
tion monitoring.15 These devices are
rapidly becoming more sophisticated, mea-
suring properties other than temperature
and pressure—such as hydrocarbons and
phase mixing.
The outlook for production logging is cer-
tainly brighter now that it has been at any
time during the last decade. Operators can
look forward not only to a better under-
standing of their reservoirs, but also to use
of this knowledge for more effectively man-
aging their assets.
—RH
ssComputed 3D droplet-averaged simulations of two-phase flow showing the effects of
shear instabilities. Mapped projections of fluid holdup are shown for horizontal (top) and
vertical (middle) lateral cross section of the borehole and at four positions cutting vertically
across a borehole (bottom). Oil (red) rises due to buoyancy forming an emulsified layer of
oil on the high side of the pipe. The lighter, upper layer flows at a higher velocity than does
the water (blue). This shear flow becomes unstable and an instability occurs that causes
the emulsion of oil to disperse in the water: large eddies mix the two phases up. Then the
process repeats farther up the pipe. Such fluid simulations help scientists test fluid-flow
models under many conditions and design better methods to measure their properties.
Technology Forum
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Oilfield Review announces its first online technology discussion.
The Production Logging Web-Forum
is an interactive site for comments on this article, inquiries about technology, or open
discussions concerning production logging tools, interpretation and applications.
To access this forum, point your browser to the following URL:
www.connect.slb.com/forums/pl/
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skipton@slb.com
15. Baker A, Gaskell J, Jeffery J, Thomas A, Veneruso T,
and Unneland T: ”Permanent Monitoring—Looking
at Lifetime Reservoir Dynamics,” Oilfield Review 7,
no. 4 (Winter 1995): 32-46.
60 Oilfield Review