Cracking the
carbonate code
Carbonate reservoirs are the most complex
reservoirs in existence, and the Middle East
is the place to find them. The complexity
and unpredictability of carbonates has
frequently frustrated geologists,
geophysicists, petrophysicists, reservoir
engineers and drillers alike.
In this article, Bernard Montaron looks at
how advances in areas such as wireless
telemetry and real-time, electronic imaging
have contributed to the now formidable and
versatile range of formation evaluationwhile-drilling tools.
hat is the definition of
‘carbonates’? Carbonates mean
different things to different people.
Geologists have described them as
“often unpredictable, even when the
depositional environment is well
understood and with a good geology
model” and “le caillou qui rend fou”,
which translates from the French as “the
rock that makes you nuts”.
For geophysicists, carbonate rocks are
known to “ring like a bell”. In the Middle
East, they present formidable challenges,
such as the yet-to-be resolved issue of
obtaining good seismic data for the deep
Khuff gas reservoir in Saudi Arabia.
Archie’s Law applies very well to
water-wet clastic formations all over the
world, and petrophysicists would love to
have such a universal law for predicting
the oil saturation of carbonates, but
there is no such thing.
For reservoir engineers, carbonates
certainly form the most complex
reservoirs in existence. Carbonate
reservoirs are very difficult to model
because the behavior of permeability
versus porosity is usually nonlinear, and
the importance of fractures, vugs, and
faults is amplified.
Finally, drillers experience a very wide
range of drilling conditions in carbonate
formations. These vary from very soft
formations to extremely hard rocks, and
there are often massive and
unpredictable drilling fluid losses.
The common factor in all these
observations about carbonates is that
W
PowerPulse
they are unpredictable – the question is
how to deal with this unpredictability.
Like the weather forecast, one of the
best lines of attack is to use a good
model to combine the understanding of
the physics with as much high-quality
experimental data as can be obtained.
Information gathered like this
gradually improves predictability,
and there is a need for new loggingwhile-drilling (LWD) technology to
allow geologists, geophysicists,
petrophysicists, reservoir engineers and
drillers to improve control over
carbonate reservoirs.
Schlumberger Anadrill has made
specific developments to address
formation evaluation while drilling
(FEWD) for carbonates:
• Enhancements to propagation
resistivity tools to increase their
measurement range to better fit
carbonates
• High-quality wellbore images that
can be acquired from resistivity,
density and photoelectric factor
measurements while drilling
• The GeoVISION* downhole
MWD/LWD imaging services
• Improvements to the MWD telemetry
system and data compression
techniques that now allow images to be
transmitted in real-time while drilling
• The introduction of seismic MWD
services using the ISONIC* IDEAL
sonic while drilling tool – this could be
used to acquire seismic data in deep
Khuff wells and elsewhere
DWOB
• The optimum way information can be
used to help drill more efficiently
through carbonates and other Middle
Eastern formations, using NDS* No
Drilling Surprises.
VISION – eyes downhole
VISION* downhole MWD/LWD imaging
services (Figure 5.1) utilize a large family
of LWD tools to provide propagation
resistivity (ARC* Array Resistivity
Compensated tool), laterolog type
resistivity (RAB* Resistivity-at-the-Bit
tool and GeoVISION), density,
photoelectric factor and porosity (ADN*
Azimuthal Density neutron tool), and
sonic while drilling (ISONIC tool). The
tools can be used in any combination with
no compromise on rate of penetration or
data quality through the PowerPulse*
MWD telemetry system and IMPulse*
integrated MWD platform that use highdata-rate telemetry.
For health, safety and environment
reasons, the ADN tool is always placed at
the top of the bottomhole assembly so
that radioactive sources can be fished out
in the event the tools are lost in the hole.
A complete triple combo is available for
FEWD in 6-in. holes, which represent a
large proportion of the drains drilled in
the Middle East.
PowerPak
steerable motor
ARC
17 1/2 in. hole
12 bits/sec Weight/torque Multidepth
MWD telemetry
resistivity and APWD
GeoSteering
ADN tool
density/neutron/Pe
PowerPulse
DWOB
ARC
12 bits/sec Weight/torque
Multidepth
MWD telemetry
resistivity and APWD
12 1/4 and 8 1/2 in. holes
PowerPak
steerable motor
GeoSteering
and AIM tool
GeoDrilling
ISONIC tool
Wireless telemetry
GeoVISION tool
Wireless telemetry
ADN tool
Number 2, 2001
58
IMPulse
6in. hole
density/neutron/Pe
Middle East Reservoir Review
MWD telemetry, APWD
and multidepth resistivity
PowerPak
steerable motor
AIM
tool
Figure 5.1: The
Schlumberger Drilling and
Measurements VISION family
of LWD tools
BF
VR2
VR1
IF
34 in. 28 in. 22 in. 16 in. 10 in.
IT
BF
BT
IF
IT
VR2 and VR1
Figure 5.2: The ARC tool and its method of operation
Resistivity, ohm-m
20,000
10,000
HLLD
1,000
HLLS
100
20
2,000
2,100
2,200
2,300
2,400
2,500
2,600
20,000
10,000
10in.
16in.
1,000
22in.
28in.
100
34in.
20
2,000
2,100
2,200
2,300
Depth, ft
2,400
2,500
2,600
Number 2, 2001
The ARC* Array Resistivity
Compensated tool is a 2 MHz and
400 kHz electromagnetic-wavepropagation tool that has two receivers
and five transmitters (Figure 5.2 left). It
provides 10 depths of investigation,
allowing measurement of five phase-shift
resistivities and five attenuation
resistivities. It can also provide gammaray data.
Like induction tools, ARC tools induce
alternating currents (red loops) in the
formation that are generated by a
variable magnetic field (green). In turn,
these currents looping around the tool
generate a variable secondary magnetic
field (red) that is detected by the
receiver antennae (Figure 5.2 right).
Another way to explain how these
tools work, is to imagine an
electromagnetic wave being emitted by
the transmitter and propagating through
the formation in all directions. This wave
is detected by both receivers, which
measure its phase and amplitude, and
then provide a phase shift (the
difference between the two phases) and
an attenuation (the ratio between the
two amplitudes). The phase shift and
the attenuation are both affected in
different ways by the dielectric and
resistivity parameters of the formation.
Formation magnetic field
Transmitted magnetic field
Formation current
Transmitted current
Received voltages
Unlike laterolog tools, no current
actually leaves or returns to the ARC
tool, which makes it ideal for operation
in oil-based muds.
Propagation tools were introduced
more than ten years ago. The first
generation tools (CDR* Compensated
Dual Resistivity tool) provided two
borehole-compensated measurements,
one phase-shift resistivity and one
attenuation resistivity.
Extraction of the apparent resistivity
from the phase-shift and attenuation
measurements is made possible by the
Rps, ohm-m
Propagation resistivity tools
BT
good correlation between the dielectric
constant and the resistivity of most
rocks. However, the accuracy of these
tools decreases with increasing
resistivity (higher than 200ohm-m).
Until recently, his was a serious
limitation in the propagation resistivity
tools for carbonates.
Phase-shift resistivities generally
provide better quality data for formation
evaluation than attenuation resistivities,
especially above 50 ohm-m. This is the
value above which attenuation resistivities
are considered meaningless. The ARC5
logs shown in Figure 5.3 are clipped at
1000 ohm-m, but should be considered
quantitative only up to 200 ohm-m.
Discrepancies between ARC5 and
laterolog data increase as the
resistivity increases. There is a very
good match at around 2260 ft between
the deep 34-in. phase shift resistivity
(red curve), which is not affected by
invasion, and the laterolog curve
showing approximately 200 ohm-m. On
the other hand, there is a large
discrepancy at 2,050 ft for laterolog
resistivities around 10,000 ohm-m. This
clearly shows the limitation of
conventional, phase-shift resistivity
provided by propagation tools.
Unlike the CDR, which provides only
two measurements, the ARC tool
features 10 different resistivity
measurements enabling inversion for
dielectric constant and for invasion (see
Figure 5.4). The mud resistivity
corrected for downhole conditions is
also a known input.
Figure 5.3: Comparison between a wireline laterolog tool and the ARC5
phase-shift resistivities in a vertical well and a Texas carbonate formation
Middle East Reservoir Review
59
Rex - 10 in.
Rex - 16 in.
Rex - 22 in.
Rex - 28 in.
Rex - 34 in.
Ea
Assumption:
limited WBM
invasion
Rxo
Di
Rt
Figure 5.4: Inversion algorithm for the ARC tool
Rex (ohm−m)
10,000
10 in.
16 in.
22 in.
28 in.
34 in.
1000
Figure 5.5:
Dielectricindependent
resistivities (Rex)
for the five
antennae spacings
100
20
2000
2100
2200
2300
2400
Depth, (ft)
2500
20,000
Rex_34
HLLD
HLLS
28 in.
34 in.
10,000
R (ohm−m)
2600
1000
100
20
Number 2, 2001
60
2000
Middle East Reservoir Review
2100
2200
2300
2400
Depth, (ft)
2500
2600
Figure 5.6:
Comparison
between dielectricindependent Rex
reading (34 in.
spacing) and
laterolog
1000 ohm-m. Conventional processing of
phase-shift resistivities is then carried
out as before.
Although it is not as good as the
inversion technique, the advantages of
this approach are that it can be adapted
to older tools such as the CDR tool, and
that it offers the same robustness as the
well-proven conventional processing.
Very good agreement exists between
the deep (34-in.-spacing) phase-shift
resistivity processed with the new
dielectric approximation and the logs
shown in Figure 5.6. Agreement is
excellent up to 500 ohm-m but degrades
as the resistivity increases beyond
1000 ohm-m.
In a horizontal well drilled several
years ago in Abu Dhabi, a 43/4-in. ARC
tool was run, and the phase-shift
resistivity data were processed to
determine the invasion profile (bottom
view Figure 5.7). The 61/8-in. hole is in
gauge (shown in black) and the invasion
radius is plotted against depth (red
curve). The dark-brown area
corresponds to the invaded zone (Rxo).
The color of the background is coded as
a function of Rt.
The darker zone between X2,075 ft
and X2,100 ft corresponds to a lowresistivity zone that is a fault zone filled
with salty water. The top log clearly
shows this is a fault, i.e., a feature that is
perpendicular to the well path, because
all the resistivity curves, regardless of
their depth of investigation, fall at the
same time (at X2,075 ft) and rise at the
same time (around X2,100 ft).
To summarise, widening the
resistivity range of propagation
resistivity tools was carried out
primarily to meet the requirements of
FEWD in carbonate formations.
Resistivity, ohm-m
Rps - 10in.
Rps - 16in.
Rps - 22in.
Rps - 28in.
Rps - 34in.
Rad - 10in.
Rad - 16in.
Rad - 22in.
Rad - 28in.
Rad - 34in.
Rm
Unlike for conventional, phase-shift
resistivities, there is no need to clip the
logs at 1000 ohm-m because the data
remain meaningful over a much wider
range of resistivity, well beyond
1000 ohm-m (Figure 5.5).
The comparison between the deepest
Rex reading (Figure 5.6: 34-in. spacing –
in red) and the laterolog logs shows an
excellent match, even for resistivities as
high as 10,000 ohm-m. Measurement
uncertainties linked to the tool electronics
and the air calibration, limit the range for
quantitative FEWD for Rex with ARC
tools to 1000 ohm-m. Qualitative
evaluation remains possible up to
10,000 ohm-m, as shown in this example.
Another interesting way to improve
the resistivity readings in highly
resistive formations such as carbonates,
is to refine the dielectric approximation
for resistivities above 100 ohm-m. The
approximation can be improved by
adding the asymptotic limit value for
the dielectric constant to correspond
with the dielectric constant of a rock
with no porosity. Doing this does not
change the curve much for resistivities
of less than 100 ohm-m, but makes a big
difference for resistivities higher than
Invasion radius, in.
With all these inputs, it is no longer
necessary to assume a relationship
between the dielectric constant and the
resistivity. One can invert for the
dielectric constant and calculate the
apparent resistivity of the formation for
the various depths of investigation
(antennae spacings, denoted Rex).
It is assumed that the invasion is
limited, so that the deepest readings
(34-in. phase shift and attenuation) are
virtually unaffected. This is generally the
case at drilling time. From there, one
can also invert for invasion using the
shallower readings and provide Rt,
Rxo and Di.
Phase resistivity
Rm – 0.024 ohm-m
100
100
1
X1,950 X2,000 X2,050 X2,100 X2,150 X2,200
Depth, ft
Phase resistivity Radial profile image
15
10
5
0
5
10
15
X1,950 X2,000 X2,050 X2,100 X2,150 X2,200
Depth, ft
Figure 5.7: Abu Dhabi example –
ARC invasion profile image
GeoVISION – Resistivity-atthe-bit tool
The RAB tool (see Figure 5.8) was
introduced six years ago and has been
used successfully since. However, its
resistivity range is limited to
20,000 ohm-m, and, until recently, there
Figure 5.8: GeoVision tool
X0
Figure 5.9: The new
inversion algorithm
(Di Rt, Rxo) for the
GeoVISION and
RAB tools
Rh
Ri
X10
Shadow
Depth, ft
The new, dielectric-independent
processing technique was developed for
ARC tools. It provides five resistivities
that are good for quantitative FEWD up
to 1,000 ohm-m, and usable for qualitative
evaluation up to 10,000 ohm-m. An
improved dielectric approximation
has also been developed that gives
quantitative phase-shift resistivity
readings up to 500 ohm-m and qualitative
information up to 5000 ohm-m. This
method can be used to reprocess the data
from all tools, including the oldergeneration CDR tool.
X20
R1
X30
Ring
BD
BM
BS
Rxo
Rt
Rxo
X40
0 0.2 0.4 -15 -5
5 15
Radius, in.
1
10
100
Resistivity, ohm-m
was no reliable inversion algorithm to
derive Rt, Rxo and Di from the five
measurements available.
GeoVISION* downhole MWD/LWD
imaging services are the new-generation
RAB tools. The electronic hardware has
been improved and the button
electrodes redesigned to provide a
focused resistivity measurement with a
range up to 200,000 ohm-m, similar to
wireline laterolog tools. They are the
only focused resistivity laterolog type
LWD tools available in the industry
today, and are perfectly suited to FEWD
in carbonate formations when drilled
with water-based muds.
The tools provide five resistivity
measurements:
• Resistivity, using the bit as an
electrode, which is an excellent tool
for casing or coring point selection
• High-resolution, ring resistivity
• Three button resistivities: shallow,
medium and deep
• Gamma ray
• Axial shock.
As the tool rotates, the buttons scan
the wellbore and resistivity values are
recorded in the tool memory in 56 bins
(angular sectors) around the wellbore,
allowing the generation of three
wellbore images.
A new inversion algorithm was
developed that can be applied for RAB
and GeoVISION tools. This algorithm was
shown to be accurate up to a diameter of
invasion of the order of 25 in.
The log shown (Figure 5.9), is the
result of the inversion of data acquired
in a carbonate formation drilled with a
salt-saturated mud. Rt (red curve), Rxo
(blue curve) and the invasion profile
(track 2 – Di in blue and the hole
diameter in yellow) are shown.
Note that the shallow button
resistivity (in green) reads less than
1 ohm-m, i.e., lower than Rxo from X00
to X26 ft. This is due to the effect of the
enlarged borehole in this interval.
High-resolution
borehole ‘caliper’
An important feature of the new
technique is that borehole and invasion
effects are accounted for simultaneously.
This eliminates the need for borehole
corrections prior to inversion. This was
difficult to achieve previously, due to the
absence of a mechanical caliper while
drilling. The new technique automatically
solves the problem for borehole diameter
and leads to accurate Rt values in
overgauge and oval boreholes.
The hole diameter is derived in all
56 azimuthal directions in order to
provide a complete borehole cross
section, which is extremely useful for
geomechanical applications.
Figure 5.10 shows the shape of the
borehole at three logged depths. In effect,
it is a 3D picture. The shallow (green),
medium (blue), and deep (red) button
resistivities in each of the 56 azimuthal
bins are inverted in order to obtain the
hole radius in 56 azimuthal sectors of the
borehole. A hole breakout is clearly
observed in the 120–300° azimuth.
As the GeoVISION tool rotates, the
three buttons scan the wellbore at three
depths of investigation: 1 in. for the
Number 2, 2001
Middle East Reservoir Review
61
120
GeoVISION wellbore images
90
60
8-in.
6-in. 30
4-in.
2-in.
150
0
180
4.25-in.
210
330
300
240
270
Figure 5.10: Derived borehole shape at three
logged depths showing borehole breakout
shallow button (green), 3 in. for the
medium button (blue) and 5 in. for the
deep button (red). The resistivity data
are recorded in the tool’s memory, from
which images can be generated later on
the surface computer.
Figure 5.11: Shallow,
medium and deep
images for a 28-ft
interval showing
borehole breakout
X690
The three wellbore images (shallow,
medium and deep) are shown in Figure
5.11 for a 28-ft interval. The black curve
on the right is the gamma-ray log.
The color curve in each image is the
360°-average button resistivity for the
corresponding button.
The black patches seen, for example
at X694 ft and X700 ft, in the shallow
image clearly correspond to hole
breakouts at two opposite azimuths.
Most breakout patches disappear in
the deep image, as would be expected.
The features remaining in the deep
image are formation related. Several
bedding planes are clearly
distinguished, and correlate well with
the gamma-ray and deep-resistivity
logs. Note the layered formation at
X692 ft with beds as thin as 2 in.
High-quality images like this help to
clear up a number of log interpretation
issues. For example, some of the
Borehole
breakcut
X700
X710
Shallow
Figure 5.12:
Comparison between
drilling images, and
washdown images
acquired several
hours later.
Permeable zones
invaded with
conductive mud are
seen at X084 and
X104 ft, and breakout
at X120 ft
Number 2, 2001
62
MD
1 : 140
ft U
X 080
X 090
X 100
X 110
X 120
Middle East Reservoir Review
Drilling image
R
B L
Deep
Medium
U
Washdown image
R
B L
Resistivity overlay
2
( ohm-m)
200
features seen on the shallow resistivity
log are clearly caused by breakout holes
filled with conductive mud.
GeoVISION can also be used to record
images of the same formation at
different times. In Figure 5.12, the image
on the left was acquired at drilling time,
while the image on the right was
acquired several hours later during a
washdown. The ring resistivity logs are
overlain in track 3. The separations seen
(blue-filled zones), are not all due to
invasion and the image helps in making
the correct interpretation.
The zones at X084 ft and X104 ft
correspond to permeable zones that
have been invaded by conductive mud.
On the other hand, the blue zone on the
log at X120 ft clearly corresponds to a
characteristic hole breakout, as
evidenced by the two dark patches in
two opposite azimuths.
The GeoVISION tool provides
geologists and drillers with ‘eyes’
downhole. It can be used for real-time
identification of formation dips,
beddings, fractures, faults, and to help
to geosteer the well.
The FMI* Fullbore Formation
MicroImager has a resolution of 0.2 in.,
and sensing electrodes located on four
pads. The resolution of the GeoVISION
tool is limited by the size of the buttons
to about 2 in.
The depth scale on Figure 5.13 has
been expanded by a large factor
(unusually large for a LWD log) and
shows a 7-ft interval. Despite its lower
resolution, the GeoVISION tool (right
image) clearly identifies the main
structural features in the formations,
and accurate dips are obtained. Bedding
surfaces as thin as 2 in. can be observed.
Comparing FMI and GeoVISION images
for fractures (Figure 5.14), the largeamplitude sine line in yellow seen on the
GeoVISION image corresponds to a
bedding surface that is intersected by the
well trajectory at a very low angle of
incidence (almost parallel to the bedding
plane). The dark lines that are not
horizontal are fractures invaded with
conductive mud. Some of them are less
than 2-in. wide but they are still detected.
Figure 5.15 shows a fault plane
imaged with reasonable agreement
between the dips. The plane is
interpreted as a fault because of its
relationship with the bedding,
FMI
Geovision
FMI
Geovision
Figure 5.13:
Comparison of FMI
with GeoVISION for
dips and beddings
1ft
Figure 5.14:
Comparison of FMI
with GeoVISION for
fractures
Fractures
1ft
Bedding
FMI
Geovision
Figure 5.15:
Comparison of FMI
with GeoVISION for
faults
1ft
Number 2, 2001
Middle East Reservoir Review
63
Pressure
Time
Pressure
Time
Pressure
Time
Pressure
Time
Figure 5.16: The PowerPulse MWD
Number 2, 2001
64
(not shown here). The high true dip of
about 80° makes this more likely to be a
fault than bedding.
The PowerPulse MWD telemetry
system (see Figure 5.16) is the
workhorse of Schlumberger’s real-time
MWD/LWD services. In the 10 years
since its introduction it has become the
industry’s most reliable MWD tool.
Recent improvements to the telemetry,
or ‘zero-gap’ modulator, have boosted
the amplitude of the pressure pulses by
30%. These advances, in conjunction
with recent improvements to modulation
and demodulation techniques, have
produced mud-pulse telemetry data
rates of 12 bits/sec, making it, by far, the
fastest telemetry-data-rate MWD tool in
the industry.
Middle East Reservoir Review
Such performance directly affects the
quality of the data transmitted in real
time. Data transmission requirements
can be completely decoupled from
the rate of penetration without
compromising data quality. Real-time
logs that are as good as memory logs can
be produced if required. The tool’s data
transmission capabilities can be further
enhanced using data-compression
techniques. This is particularly useful
when drilling long, extended-reach wells
where it may be necessary to lower the
MWD telemetry frequency to 1 Hz.
Three factors contribute to the
exceptional quality of real-time wellbore
images, see Figure 5.17. Firstly, drilling
rates are generally fairly slow, typically
60 ft/hr. Secondly, mud-pulse telemetry
rates are high, so, for example, at 6 bits
per second a total of 360 bits is
transmitted for each foot drilled. Thirdly,
image resolution does not need to be
much greater than tool resolution, which
is limited to about 2 in. It therefore
follows that an image of a 2-in. slice of
formation in an 81/2-in. wellbore using
pixel resistivities coded with 16 colors,
requires only 52 bits for real-time
transmission. In practice, data
compression techniques are based on
complex algorithms similar to those
used to transmit images from the space
probes exploring our outer solar system.
Recorded image
Depth, ft
X050
X100
X150
X200
X250
X300
X350
X400
Real-time image, compression factor 64
Depth, ft
X050
X100
X150
X200
X250
Figure 5.17: Comparison of real-time and stored
wellbore images
Neutron detectors
LINC coils
Neutron source
Electronic source
Density source
X300
X350
X400
ADN Azimuthal Density
Neutron tool
Some carbonate reservoirs display a
fairly flat, high-value resistivity log. In
these cases, porosity becomes the most
useful measurement for placing the
drain in the sweet spots of the reservoir.
Porosity measurements are made with
the ADN* Azimuthal Density Neutron
tool (Figure 5.18).
The ADN tool has neutron and
gamma-ray sources that are attached
with a titanium rod to a fishing head. It
makes four azimuthal density and
photoelectric factor measurements (up,
down, left and right). This is possible
because gamma rays can be detected
through a fairly narrow, angular window
and the formation is scanned for gamma
rays as the tool rotates. Not only can the
ADN make measurements in the four
quadrants, but it can also record
wellbore density and photoelectric
factor images with 16 angular sectors
around the wellbore.
The ADN tool also measures neutron
porosity. Neutrons have a life of their
own: they tend to scatter widely in the
formation through multiple interactions,
and they can also pass through the steel
body of the tool. Because of this, only one
average porosity measurement is made.
The 16 sectors are clearly visible in
Figure 5.19. The limitation to 16 sectors
comes from the requirement to obtain
acceptable statistics for the gamma-ray
counts in each sector.
X200
Density detectors
X250
Ultasonic sensor
X300
Batteries
X350
Tool bus
Figure 5.19: Example of a density image showing
sand–shale layering
Number 2, 2001
Figure 5.18: The ADN tool
Middle East Reservoir Review
65
PeF U/D PeF L/R
RHOB U/D RHOB L/R
PeF image
Density image
X000
14 ft =
2.5°
Top of
porosity
Sliding mode
The left-hand image is a true
representation of density, and the other
image is a representation with the color
scale optimized to enhance contrast. In
the X250–X300-ft interval, azimuthal
density was the only measurement that
identified the sand–shale layering.
Gamma-ray, resistivity, neutron and
average density measurements all
indicate that the zone is homogeneous.
It can be seen from this example that
displaying or utilizing maximum density
would not be correct and would greatly
underestimate the porosity.
X100
Middle East well
log examples
Figure 5.20: Density and PeF images
PeFimage
image
PeF
Density image
10 ft
X500
Bedded pyrite layer
Figure 5.21: Pyrite bed from PeF image
PeFimage
image
PeF
Density image
Fault plane
Figure 5.22: Density image fault detection
Number 2, 2001
66
Middle East Reservoir Review
The ADN logs on this page were
obtained from a 61/8-in. horizontal well
in the United Arab Emirates.
Despite the modest resolution,
formation dips are easily determined
from these images. Since there is no
GeoVISION tool currently available in
43/4-in. size, the ADN 43/4-in. images are
even more valuable.
The four photoelectric factor (PeF)
quadrant logs (up, down, left, right) and
the corresponding PeF image are shown
on the left side of Figure 5.20. The
density image and quadrant logs are
shown on the right side. As with
GeoVISION resistivity images, the green
bar corresponds to a sliding interval (no
rotation – no wellbore scanning). In this
interval, only the porosity, and the
bottom density and PeF are used.
In this 130-ft interval the PeF does
not show any character. However,
interesting structures can be seen on the
density image and logs. The dip of the
bedding at X020 ft can be directly
determined in real time from the up and
down density logs. The up and down
logs are shifted by 14 ft, and the left and
right logs are on top of each other. The
well trajectory intersects the bedding
plane at an angle of 2.5°, which is
directly calculated from the 14-ft shift
and the hole diameter.
The same well over another depth
interval is shown in Figure 5.21. Here,
the PeF image and logs correspond well
to a thin pyrite layer that can also be
observed on the density log.
The shift between the up and down
logs is observed again, this time with a
lower value, indicating a slightly higher
incidence angle. However, the down
curve reacts before the up curve,
showing that the bedding plane is
intersected from above.
Other interesting images in the same
well are shown in Figure 5.22. These
indicate a fault plane on both density
and PeF images and logs. The transition
is interpreted as a fault, because
up/down and left/right logs react at
exactly the same time, indicating that
the feature is perpendicular to the well
trajectory (or at a very high angle of
incidence compared to the formation
dips in the same zone).
The ISONIC tool
The ISONIC tool produces real-time ∆t
measurement to enable drilling with
‘look ahead’ in thick carbonate reservoirs
(Figure 5.23).
One objective for every geophysicist is
to correlate time-based surface seismic
data with depth. Using the sonic data
provided by wireline or LWD tools, the
geophysicist can tie the prospect found
on the seismic map to the formations
that are actually drilled.
First, the compressional slowness is
incorporated with density data to
compute an acoustic-impedance curve.
The acoustic-impedance curve is then
converted to a synthetic seismogram
that is used to correlate with the surface
seismic trace extracted along the
wellbore trajectory. Once these are
correlated, the geophysicist has a depth
tie for the surface seismic. The ISONIC
tool produces ∆t in real time, so the
seismic tie can be done in real time. This
provides a unique opportunity to tie
surface seismic to depth before the well
reaches total depth.
The ISONIC tool (Figure 5.23)
consists of a monopole sonic transmitter
and a 2-ft array of four receivers
embedded in a drill collar. The tool has
two different applications: real time and
recorded mode. During the drilling
process, the transmitter is fired and
acoustic waves are propagated through
the mud and formation to the four
receivers. Four waveforms (one from
each receiver) are recorded and stored
in downhole memory. The compressional
transit time of the formation is extracted
by downhole waveform processing and is
then sent to the surface via MWD mudpulse telemetry.
Although the ISONIC tool has been
optimized to measure compressional
waves, it can also measure the velocity
of shear waves in fast rocks, as is often
the case in carbonate formations.
Figure 5.23: The ISONIC tool
Figure 5.24: Looking
ahead at the bit.
M-Base D10 expected
at 9800 ft, ISONIC
showed 9860 ft
Depth, ft
7000
RAD CDR
Reflectivity
RPS CDR
Velocity
Impedance Synthetics Seis along I
GR CDR v(DT ISONIC) Impedance Synthetics Seis along I
Reference section
7000
7500
7500
8000
8000
8500
M-Top D1
M-Top D1
M-Base D8
M-Base D8
M-Base D10
M-Base D10
9000
9500
8500
9000
9500
10,000
10,500
10,500
Middle East Reservoir Review
Number 2, 2001
10,000
67
Geosteering with
borehole seismic
Number 2, 2001
68
Drilling a vertical well without seismic
data in a thick reservoir with a
heterogeneous distribution of porous
zones is largely a matter of chance. But
if borehole seismics could be used in
real time, a new kind of geosteering is
conceivable – ‘vertical geosteering’ –
to try to intersect as many bright spots
as possible on the way down to total
depth (Figure 5.26).
Hydraulic fracturing could then be
used to further increase productivity.
This technique, which would associate
SWD or seismic MWD services with
directional drilling and hydraulic
fracturing services, could provide a
solution for optimizing the productivity
of gas wells in thick carbonate reservoirs,
such as the deep Khuff in Saudi Arabia.
Middle East Reservoir Review
Sensor
Drill bit seismic
Surface
system
Sensor
weights
oor
a fl
Se
Drill bit
ic
ism
Se ctor
le
ref
Seismic MWD
MWD telemetry
A synthetic seismogram can be
generated on the surface computer in
real time from the ∆t transmitted
through the MWD telemetry.
Once the surface seismic is tied to
depth, seismic ‘bright spots’ and other
significant features can be defined
relative to driller’s depth. This provides a
‘look ahead’ of the bit, which can be
used to make better decisions on casing
point and total depth (see Figure 5.24).
The look ahead relies on the
availability of a seismic vertical slice. But
there are cases where such seismic data
are not available. Seismic data can be
acquired while drilling, either by drill-bit
seismics (also called seismic while
drilling (SWD)), or by seismic MWD.
Drill-bit seismics use the rock bit as
the source of compressional seismic
energy. The seismic waves and the
reflected waves propagate through the
formation back to surface where they
are detected by an array of geophones.
The drill-bit vibrations also propagate
through the steel drillpipe back to
surface where they are detected by an
accelerometer installed on the
standpipe. This can be done offshore
(Figure 5.25), but it is actually easier to
do on land.
Cross correlation of the accelerometer
signal with the geophone signals, and a
lot of stacking produce a seismic image
that takes the form of a vertical cone of
about 30° looking down the bit.
oor
a fl
Se
LWD tool
ic
ism
Se ctor
le
ref
Figure 5.25: Borehole seismic while drilling. Left, drill-bit
seismic, middle, seismic MWD, right, a ‘seismic’ cone
Figure 5.26: Vertical
geosteering is
conceivable to
intersect as many
bright spots as
possible
Drilling with information
Drillers have been using roller cone bits
and PDC bits for a long time, and,
although the technology of bits is
constantly progressing, this is considered
a well-proven and mature technique. On
the other hand, drilling with ‘bits of
information’ is a domain that is still
young and has a tremendous potential to
contribute to drilling efficiency.
One of the challenges is to capture the
large volumes of information from
measurements, directional drilling
experience and drilling monitoring from
a company’s DD, MWD and LWD
engineers, and to transform it into
knowledge that is easily accessible as
input to the development of new wells.
This is the aim of the PERFORM*
Performance Through Risk Management
Process package with its DrillBase,
DrillMAP, DrillCAST and DrillTrak
applications and database, and the No
Drilling Surprises initiative at
Schlumberger Drilling and
Measurements (Figure 5.27).
The PERFORM engineer analyses all
the data and events recorded in real
time and compares them with past
experience, recent or distant, local or
global. The driller and the operating
company can then be advised on ways to
avoid drilling problems, to increase the
rate of penetration or to minimise
drilling costs.
Second well
First well
Offset data
Knowledge hub
Best practices
Subsequent wells
Events, near misses,
solutions
DrillBase
Drilling events database
Road map
of potential
hazards
with
contingencies
Forecast of
hazards
Best practices
Contingencies
Record of
events
versus
plan
DrillMap DrillCAST DrillTrak DrillMAP DrillCAST DrillTrak DrillMap DrillCAST DrillTrak
Figure 5.27: PERFORM process for drilling knowledge management.
The aim is to reduce costs and nonproductive time by integrating
planning and real-time drilling solutions
The PERFORM service was introduced
in the Middle East in 2000 and, as a
direct result, Schlumberger broke several
drilling records in Saudi Arabia and in
Abu Dhabi. In Abu Dhabi, the PERFORM
engineer, analyzed the data and
recommended the use of new BHA
designs that represented a significant
change to local drilling and directional
drilling habits. This resulted in dramatic
rig-time reductions, with wells drilled in
less than 20 days compared to more than
30 days prior to these changes. This
meant total savings of the order of half a
million dollars per well.
Conclusions
• The introduction of a new-generation,
focused laterolog LWD tool,
GeoVISION, with a measurement
range exceeding 20,000 ohm-m, and
that provides wellbore resistivity
images useful in visualizing beddings,
fractures and faults
• Full VISION triple-combo LWD
services in 6-in. holes
• Real-time wellbore images using
resistivity, density and PeF scans
• PERFORM service for drilling faster
and improved wells.
These advances are bringing higher
quality data and drilling knowledge that
are helping to turn the unpredictable
nature of carbonates into predictable
wells throughout the Middle East.
Most reservoirs in the Middle East have
carbonate formations, and long ago
Schlumberger Drilling and
Measurements recognized the need to
address their problems with specific
solutions developed for FEWD and
drilling of carbonates.
The main advances made as a result of
these efforts are:
• A new processing algorithm for
propagation resistivity tools that
expands their resistivity range well
beyond 1000 ohm-m
Number 2, 2001
Middle East Reservoir Review
69