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7/28/2019 Section 11 - Sonic Logging
http://slidepdf.com/reader/full/section-11-sonic-logging 1/21
MSc Drilling & Well Engineering
Formation Evaluation SONIC LOGGING
Introduction.
The sonic, or acoustic log, was developed to provide a detailed record of seismic velocity, and
even today the majority of sonic logs are run for this purpose, particularly in surface andintermediate logging runs.
The tool received wide acceptance also as a porosity tool, in addition to the density and
neutron logging devices, and for the purpose of stratigraphic correlation and lithology
assessment.
Further seismic application has recently been acquired with the inception of new seismic
techniques, which aid in the search for hydrocarbons.
Principle.
The sonic tool measures the time it takes for a sound pulse to travel from a transmitter to a
receiver. The sound pulses are oscillatory waveforms with contributions from different wave
types, of which the compressional, or longitudal wave (P wave), and the transverse, or shear
wave (S wave), are the most important. Only the compressional wave is propagated in liquid.
The energy transmitted by the slower shear wave is much higher than that of the faster
compressional wave. The receiver is triggered by the fastest wave, which is the compressional
wave, and therefore, the first "arrival".
Figure 1 shows a schematic drawing of the travel time and the amplitude of the compressionaland shear wave.
Fig. 1: Separation of compressional and shear wave travel times and amplitudes.(courtesy of Schlumberger)
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MSc Drilling & Well Engineering
Formation Evaluation The sound emissions from the sonic, or acoustic tool, have a frequency between 20 - 40 kHz,
or 20,000 - 40,000 cycles per second. The transmitter emits in general 20 pulses per second
(10 - 60, depending on the tool). The sound wave spreads in all directions from the transmitter,
thereby producing spherical wave fronts.
The parameter measured is the reciprocal velocity, called the travel time ∆T, expressed in
microseconds per foot. The velocity of the sound pulses V is expressed in feet per second,
thus:
∆T = 106/V
The velocity of the compressional wave depends on the elastic properties of the rock matrix
and the fluids in the pore space. The measured travel time is, therefore, a function of rock
matrix, formation fluids and porosity.
The compressional wave travels through the mud at a relatively low velocity, VL1, is refractedat the formation face and passes through the formation at a velocity VL2, which is higher than
the velocity in the mud.
Fig. 2:
Reflection and refraction
of a compressional
wave.
Fig. 3 : Reflection and refraction atthe critical angle.
Equipment
According to the refraction law, the following
formula applies:
sin i/VL1 = sin R/VL2
An example is shown in Figure 2.
At the critical angle of refraction, R = 90o,
thus:
sin i = VL1/VL2
Thus, if the velocity of sound in the formation
changes, the critical angle changes.
The compressional waves, refracted at the
critical angle, propagate along the borehole
wall at a speed VL2.
Each point reached by the wave acts as a new
source transmitting waves, creating
effectively waves of cones in the mud
traveling at a speed VL1.
Figure 3 shows the reflection and refraction at
the critical angle.
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MSc Drilling & Well Engineering
Formation Evaluation Early tools, as shown in Figure 4, consisted of one transmitter and one receiver, mounted on a
rubber body (low velocity, high attenuation). The travel time measured with these tools,
however, is too long, due to the passage of sound through the mud (A + C). Moreover the
physical length of formation through which the sound wave traveled (B), is not constant, as
changes in the velocity alter the critical refraction angle.
To overcome this problem, the next generation of tools, as shown in Figure 5, consisted of one
transmitter and two receivers. The distance between the transmitter and receiver was greater
than 5 feet, with the receivers either 1 or 3 feet apart. This system measures in effect the time
between the wave arrival at the two receivers. This time, known as the sonic interval transit
time ∆T, is directly proportional to the speed of sound in the formation (interval D) measured
between the two receivers R 1 and R 2.
A shortcoming of this system is observed, when the tool is tilted in the hole (C ≠ E), as shown
in Figure 6, or when the hole size changes due to wash-outs.
Fig.4: Fig. 5: Fig. 6: Fig. 7: Borehole Compensated(courtesy of Atlas Wireline Services, Sonic Log. (courtesy of
Houston, Texas) Schlumberger)
The latest version is the Borehole Compensated Sonic Log (BHC), which has two transmitters
and four receivers. In this tool the transmitters are pulsed alternately and delta T values are
obtained from alternate pairs of receivers, as indicated in Figure 7. The two delta T values are
averaged by a computer in the surface panel.
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MSc Drilling & Well Engineering
Formation Evaluation The distance between the transmitter and the first receiver is 3 feet, with 2 feet between both
receivers.
If the tool is tilted in the hole, or if
there are cavities in the borehole wall,
or a change in the hole diameter, theeffect on the travel time is eliminated
by averaging the two transit time
measurements, one for each of the
transmitter-receiver pairs.
The effect of borehole compensation
on a tilted tool can be observed in
Figure 7. The influence of a change in
the borehole diameter on the
measurements is shown in Figure 8.
Fig. 8: Influence of a change in hole diameter and
compensation on the interval transit time.
Calibration.
The calibration of the sonic log must be carried out inside the borehole, by recording the tool
response opposite pure beds of known lithology, such as an anhydrite (50.0 µs/ft.), or a salt
(66.7 µs/ft.), or inside the casing (57.1 µs/ft.).
Log Presentation.
When the sonic log is run on its own, it is presented in tracks 2 and 3, as shown in Figure 9.
The sonic interval transit times (∆T) are given in microseconds/foot, with a linear scale from
40-140 µs/ft., reading from right to left. When the sonic log is run in combination with other
wireline logging tools, the log is restricted to track 3, often with the same sensitivity scale of
40-140 µs/ft. maintained.
Fig. 9: Borehole Compensated Sonic log.
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MSc Drilling & Well Engineering
Formation Evaluation An integrated travel time (TTI) is recorded simultaneously. It shows the average velocity for
the formation logged in milliseconds (10-3 seconds), and is indicated by a series of pips on the
right hand side of the depth column. The small pips indicate an increase of the integrated
travel time of 1 millisecond, whereas the larger pips are for 10 milliseconds travel time. The
average travel time between two depths can, therefore, be found by simply counting the pips,
which is very useful in comparing sonic logs with seismic sections.
The correctness of the TTI can be checked in a homogeneous formation, by counting the
number of pips and comparing them with the product of the sonic (∆T) and the length of the
interval (h):
[delta T (microseconds/ft.) x h (ft.)] / 1000 = t (milliseconds)
Logging Characteristics.
Depth of investigation.
The first arrival of the sonic waves detected, is the compressional wave refracted at the critical
angle. Therefore, the depth of investigation should be a few centimeters. The presentation of
the sound wave, however, seems to depend on the wavelength of the sensed waves (3 x λ ).
The theoretical depth of investigation is between 12 cm and 1 meter, and should be a function
of the formation velocity.
Vertical resolution
The vertical resolution of the tool is about equal to the distance between the receiver pairs,
which is generally 2 feet.
Limitations.
Some limitations on the accuracy of sonic log data have been known to exist since the
introduction of the sonic tool. Others have recently been recognized from discrepancies
between BHC data and modern seismic results. The limitations are either of a technical or of a
physical nature.
Technical limitations.
These are associated with the trigger mechanism, the shape of the waveform and the tool
calibration.
Noise, which can be generated mechanically (rugose hole), or caused by stray electrical
interference, is picked up by the receiver electronics. If the noise peaks exceed the trigger
level (A), triggering will be premature and the time measurement will be incorrectly small. To
limit this possibility, all receiver circuits are switched off for 120 microseconds after firing the
transmitter. The time interval during which this false triggering can occur is longer for the far
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MSc Drilling & Well Engineering
Formation Evaluation receiver, and consequently most of the "noise spikes" cause the formation travel time (T2 - T1)
to be too short, as shown in Figure 10.
Fig. 10: Triggering by noise spikes. (from D.H. Thomas, 1978)
Figure 11 shows an example of noise kicks to smaller values of delta T as seen on the sonic
log.
Fig. 11: Example of noise kicks on the sonic log. (from O. Serra, 1984)
Delta T Stretch. The second and third cycles of the waveform are usually of progressively
larger amplitude. Due to the longer sound path, the signal arriving at the far receiver is usually
weaker. As the trigger level is constant for both receivers, triggering at the far receiver can
occur later on the waveform, causing delta T to be slightly too high. This is called "delta T
stretch", but is not noticeable on the log. In modern sonic tools this "delta T stretch" is
automatically corrected, and the true delta T is recorded on the log.
The actual value of delta T with the BHC Sonic log, with a 2 ft. spacing between the receivers
is ¼ x [(T4 - T2) + (T1 - T3)] microseconds/ft. (Figure 7). Thus, if both far receivers are at the
limit of delta T stretch, the total error possible will thyerefore be ¼ x [¼ cycle + ¼ cycle],
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MSc Drilling & Well Engineering
Formation Evaluation which is ⅛ of a cycle. For a 30 kHz pulse frequency, this amounts to a maximum error of 4
microseconds/ft. An illustration of delta T stretch is given in Figure 12.
Fig. 12: Schematic example of stretching. Fig. 13: Schematic example of cycle(from O. Serra, 1984) skipping. (from O. Serra, 1984)
Cycle Skipping is worse than delta T stretch, and is the occurrence of triggering at the second,
or even at the third cycle. Cycle skipping causes a marked sudden shift to a higher delta T
value, followed by a similar shift back to the correct value. The mechanism of cycle skipping
is shown in Figure 13. The magnitude of the shift can be calculated from the frequency of the
tool.
Physical limitations.
These are associated with the dimensions of the tool, the size of the borehole, and with the
characteristics of the formation close to the borehole.
The sound wave travels in all directions, but to determine the velocity of the sound in the
formation, V1, the sound wave traveling along the borehole wall should arrive at the receiver
before the sound wave transmitted through the mud with a velocity V0. The formation velocity
is measured if the distance from the transmitter to the nearest receiver is greater than the
critical distance Xc, which is given by the formula:
V1 + V0 V1 + V0 V1 + V0 Xc = (D - d)
V1 - V0
where: D = diameter of the borehole in inches
d = diameter of the tool in inches
V0 = velocity of sound in the mud in ft./sec.
V1 = velocity of sound in the formation in ft./sec.
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MSc Drilling & Well Engineering
Formation Evaluation Thus the critical distance, Xc, increases for increasing hole diameter, or a decrease in the
formation velocity. A graph of transmitter-receiver distance, X, versus the transmitter-receiver
time, delta T, is given in Figure 14, and shows that the fastest sound path to the nearest
receiver is through the mud at a spacing less than Xc.
Fig. 14: Critical transmitter to receiver distance. (from D.H. Thomas, 1978)
For example, consider the BHC-Sonic log in a 12-¼" hole, a tool diameter of 3-½" and a
transmitter-receiver spacing of 3 ft. (Xc = 36"). If the velocity of the sound in the mud, V0, is
5300 ft./sec., it can be calculated that V1 must be greater than 5965 ft./sec., or that ∆ T must be
less than 168 microseconds/ft., to obtain the correct sound velocity in the formation.
Eccentering the tool should normally overcome this limitation, but will give a weaker signal,
and may lead to noise triggering and cycle skipping. However, in large holes, eccentralisationshould be tried in order to get any signal at all with the BHC-Sonic log.
In practice there is often an altered zone between the borehole and the virgin formation. The
most common examples of formation alteration are caused by the absorption of fluid by soft
shales, resulting in a velocity reduction. Changes in stress distribution, cracking and
shattering, or extreme hole rugosity, can also cause reduction of formation velocity close to
the borehole, in reservoir rock as well as in hard shales.
The effect of the slower altered zone is analogous to that of the mud. The critical distance, Xc,
increases with increasing hole size, D, increasing depth of the altered zone and decreasing
formation velocity.
Practical experience has shown that the critical distance is seldom more than 10 feet, so that a
sonde with a transmitter-receiver spacing of about this length will produce accurate readings
in formations with altered zones close to the borehole. The BHC-Sonic, however, would read
too high a transit time under these conditions.
A plot of the transmitter-receiver time versus distance, in the presence of an altered zone close
to the borehole wall, is given in Figure 15.
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MSc Drilling & Well Engineering
Formation Evaluation It is also possible that the velocity in the altered zone is greater than the velocity in the virgin
zone. This is the case when the pore spaces of the formation are filled with solid mud particles
up to a significant distance from the hole, or with deep mud filtrate invasion in a gas-bearing
formation. In these cases, the true formation velocity cannot be obtained. A graphical
representation for this case is shown in Figure 16.
Fig. 15: Transmitter-Receiver spacing Fig. 16: Transmitter-Receiver spacing
with a low velocity altered zone. with a fast velocity altered zone.(from D.H. Thomas, 1984) (from D.H. Thomas, 1984)
The Long Spacing Sonic log should provide better seismic and petrophysical data where low
velocity altered zones exist. This is illustrated in Figure 17, for a BHC-Sonic with a 3 ft.
spacing and a Long Spacing Sonic with an 8 ft. spacing.
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MSc Drilling & Well Engineering
Formation Evaluation
The altered zone has a sound velocity of 110 µs/ft.,
as compared to the velocity in the undisturbed zone
of 90 µs/ft. The velocity of the sound in the mud is
200 µs/ft. The refraction angle has not been
considered in these calculations.
The BHC-Sonic travel time is:
T1 = (200 x ½) + (110 x 3) = 430 µs
T2 = (200 x ½) + (110 x 1) + (90 x 3) = 480 µs
The Long Spacing Sonic travel time is:
T1
= (200 x ½) + (110 x 8) = 980 µs
T2 = (200 x ½) + (110 x 1) + (90 x 8) = 930 µs
Evidently the unaltered formation signal is only
obtained with the Long Spacing Sonic.
Fig. 17: Low velocity Altered Zone.
Fig. 18: Maximum detectable delta T.(courtesy of Schlumberger)
The maximum detectable delta T is
shown in Fig. 18 for a BHC-Sonic
and for a Long Spacing Sonic.
The superior performance of the
Long Spacing Sonic is apparent.
The Long Spacing Sonic has,
however, the disadvantage that the
sound pulse has to travel further
and, therefore, the signal becomes
progressively weaker.
Incorrect triggering caused by a
poor signal to noise ratio and cycle
skipping can thus be expected.
The Long Spacing Sonic tool can be operated in the 10 - 12 ft. and the 8 -10 ft. mode, as
shown in Figure 19. Two positions in the borehole are indicated. Their displacement depicted
by the dashed line equals the interval over which the signals obtained in the lower position are
memorised to combine them with the readings obtained in the higher position. This allows
calculation of delta T over the same 2 feet interval, thus giving a resolution which is identical
to the BHC-Sonic tool. An example, showing the effect of an altered zone on the reading of
the BHC-Sonic is shown in Figure 20.
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MSc Drilling & Well Engineering
Formation Evaluation
Fig. 19: Long Spacing Sonic Tool. Fig. 20: BHC-Sonic and LSS log(courtesy Schlumberger) over an altered shale.
The interval over which the delta T is calculated with the Long Spacing Sonic is called
"isomation delta T".
The calculation of delta T for the 8 – 10 ft. mode is:
delta T = ¼ x (T1R 1 - T1R 2) + ¼ x (T2R 2 - T1R 2)
The calculation of delta T for the 10 - 12 ft. mode is:
delta T = ¼ x (T2R 1 - T2R 2) + ¼ x (T2R 1 - T1R 1)
Applications.
1. Porosity Determination.
The sonic log can be used to calculate the porosity in a reservoir, although it is usuallyinferior to the porosity values calculated from the density and neutron logs.
It is used though, both as a safeguard in porosity determination, especially as the
measurement is not very sensitive to hole size, and to compute secondary porosity in
carbonate reservoirs.
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MSc Drilling & Well Engineering
Formation Evaluation
Fig. 21: Compressional wave travel
path. (Wyllie et al., 1956)
The following relationship between velocity and porosity applies:
t Σ (Lfl/L) Σ (Lma/L)
∆t = = =
L Vfl Vma
This relationship can be re-written as follows:
∆t - ∆tma
∆t = Ø . ∆tfl + (1 - Ø) . ∆tma or, Ø =
For any given lithology, the speed of sound
in the formation is a function of porosity.
The path of a compressional wave through
a water-bearing formation is sketched inFigure 21.
Wyllie proposed an empirical relationship,
called the "time average equation". It links
the interval transit time to porosity by
taking the total interval transit time to be
equal to the sum of the interval transit
times in the matrix and in the pores.
∆tfl - ∆tma
Interval transit times and the speed of the compressional waves in various rocks,
together with those of various fluids encountered in the formations, is given in Table 1.
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Formation Evaluation Table 1
∆t (µs/ft.) Vma (ft./s) Vma (m/s)
Sandstone 55.6 - 51.3 18,000 - 19,500 5,490 - 5,950
Limestone 47.6 - 43.5 21,000 - 23,000 6,400 - 7,010
Dolomite 43.5 - 38.5 23,000 - 26,000 7,010 - 7,920
Anhydrite 50.0 20,000 6,096
Salt (Halite) 66.7 15,000 4,572
Casing 57.1 17,500 5,334
Shale 170 - 60 5,880 - 16,660 1,790 - 5,805
Bituminous Coal 140 - 100 7,140 - 10,000 2,180 - 3,050
Lignite 180 - 140 5,560 - 7,140 1,690 - 2,180
Water 200,000 ppm, 15 psi 180.5 5,540 1,690
150,000 ppm, 15 psi 186.0 5,380 1,640
100,000 ppm, 15 psi 192.3 5,200 1,580
Oil 238 4,200 1,280
Methane, 15 psi 626 1,600 490
In uncompacted formations, however, the time average equation gives porosities that are too
high. Such conditions may be indicated when adjacent shale beds exhibit ∆T values greater
than 100 µs/ft. An empirical correction factor, Bcp, is then applied to the equation. Its value is
approximately equal to the ∆T in adjacent shales divided by 100.
∆t - ∆tma 1The formula then becomes: ØS(corr) = x
∆tfl - ∆tma Bcp
The compaction factor can also be obtained with data from other logs, such as:
- A density-sonic cross-plot in clean water-bearing formations close to the zone of
interest. From the cross-plot a clean formation line is established that can be scaled in
porosity units using the density log.
- The neutron log. The neutron porosity is obtained in clean water-bearing formations.
This value should be close to the actual porosity. The compaction factor will then be:
Bcp = ØS/ØN
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MSc Drilling & Well Engineering
Formation Evaluation - The R o method. In clean water-bearing sands the porosity can be estimated from the
resistivity log if R w is known:
FR = R o/R w = Ø-m and thus: Bcp = ØS/ØR
Raymer proposed another transit time to porosity relationship, which seems more in
agreement with observations made:
Fig. 22: Raymer - Hunt equation.
1 (1 - Ø)2
Ø
= +
∆tlog ∆tma ∆tfl
This formula results in a far
superior transit time-porosity
correlation over the entire porosity
range, and suggests a more
consistent matrix velocity for a
given lithology. This relationship
is graphically presented in Figure
22. It allows determination of
porosity in unconsolidated
formations.
Both formulae apply in carbonates containing primary (inter-granular) porosity. Secondary
porosity (vugs/fractures) remains undetected by the sonic device. Density and neutron tools
record total porosity, thus the secondary porosity is obtained by deducting the sonic porosityfrom the total porosity.
When adequate core porosity data are available over the logged interval, the sonic log should
be calibrated against core porosity. The procedure is shown in Figure 23. The regression line
can be extrapolated to the matrix transit time ∆tma. Verification of the value of ∆tma can be
obtained from a cross-plot of R o versus ∆t.
.
Fig. 23: Sonic log - core porosity calibration.
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Formation Evaluation Effect of Gas on Sonic derived Porosity.
Due to its low density, gas decreases the density of the formation, which in its turn
causes an increase in the sonic transit time.
An increase in the sonic transit time, however, means that the computed porosity will
be too high.
Whether the sonic log will sense the presence of gas depends to a large extent on how
much gas is left after invasion by mud filtrate.
In medium to high-porosity gas-bearing formations, a residual gas saturation of at least
15 % would be expected in the flushed zone, so that gas will be sensed by the tool.
The increase in transit time is almost negligible in the deeper, well compacted, low porosity formations, where the pore fluid contributes little to the signal.
Effect of Shale on the Sonic derived Porosity.
The effect of shale on the sonic log response is variable and depends on the density of
the shale present in a porous and permeable formation.
Young shales, at shallow depth, are generally under-compacted and tend to increase
the sonic transit time, leading to a slightly higher log-derived porosity.
Ancient shales, on the other hand, tend to be well compacted and as dense, or even
denser than some sandstones. The presence of such a shale in a porous and permeable
formation may lead to an increase in the density of that formation, thereby reducing the
transit time, and consequently giving a lower computed porosity.
The effect of shale on the sonic log is not as dramatic as the effect of gas.
Secondary Porosity.
In general, the sonic log tends to ignore vuggy or fracture porosity common in
carbonate reservoirs. The density log and the neutron log, by contrast, respond to total porosity.
A secondary porosity index (SPI or Ø2) may therefore be derived by taking the
difference between density porosity, ØD, or neutron porosity, Ø N, and the sonic
porosity, ØS:
Ø2 = (ØD, ØN) - ØS
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Formation Evaluation 2. Correlation.
The sonic log is a sensitive recorder of a formation’s lithology, which is especially
evident in fine grained sediments or in beds without porosity. The sonic log can pick
out small variations, probably in texture, carbonate or quartz content, to show a very
distinct stratigraphical interval, despite depth differences.
3. Lithology Idenification.
The sonic velocity in common sedimentary rocks is not very diagnostic, as there is too
much variation within each type of rock. However, high velocities are more likely to
be associated with carbonates, middle velocities with sandstones and low velocities
with shales.
Velocities of certain rock types which are often encountered in nature in a very pure
state, such as halite, gypsum, anhydrite and coal, may be diagnostic, as can be seen in
Table 1.
A better lithology determination is obtained when the sonic log readings are compared
to those of the density and neutron logs (sonic-density, sonic-neutron and neutron-
density cross-plots, M and N plot or MID plot).
For thick homogeneous water-bearing formations, with a reasonable spread in porosity,
the lithology may be determined with the use of the the "Hingle" cross-plot.
4. Texture.
The travel of sound through the formation depends on the porosity, the type of matrix,
grain size distribution and shape, and on cementation.
The type, size and distribution of the pores all have an effect on the speed of sound.
The speed also depends on the intergranular contact.
In formations with low porosity (0 – 5 %) the pores are isolated and randomly
distributed. In this case the interval transit time does not vary much from the matrix
transit time, as the matrix constitutes the continuous phase for the sound wave to travel
through. On the other hand, if the porosity is very high (over 50 %), the continuous
phase for the sound wave is the fluid in the pore space. In this case the fluid transittime will be measured.
5. Fracture Identification.
Sound will travel along the fastest path between transmitter and receiver and thus
avoid fractures. Comparison of the sonic derived porosity data with data obtained from
the density and/or neutron log, may indicate the presence of fractures.
However, this should be confirmed by other means, as secondary porosity from vugs
will show the same effect.
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Formation Evaluation
6.Compaction.
As a sediment becomes compacted, the velocity to sound increases. Plotting the interval
transit time on a logarithmic scale against depth on a linear scale gives a straight linerelationship.
Fig. 24: Uplift and erosion own
by the Sonic log.
Compaction trends are constructed using
only one lithology and comparing the
same stratigraphic interval at various
depths. From these trends it is possible to
estimate the amount of erosion at
unconformities, or the amount of uplift.
Compaction is generally accompanied by
irreversible diagenetic effects, which do
not alter after uplift. The compaction of asediment represents its deepest burial.
When a general compaction curve for an
interval is available, the amount of the
over-compaction can be explained by the
uplift of the formation, as is illustrated in
Figure 24.
Therefore, any drastic changes in the
compaction curves at faults, or at
unconformities, may indicate the amount
of section that is missing.
7. Over-pressure Detection.
The sonic log can be used to detect
over-pressured zones in a well. An
increase in pore pressures is shown on
the sonic log by a drop in sonic velocity,
or an increase in the sonic travel time.
A plot of the shale interval transit time
against depth will show a change in the
"average" compaction line to higher
interval transit time values, which is
probably due to higher shale porosities
in the over-pressured zone. An example
of an over-pressured zone on a transit
time versus depth plot is shown in
Figure 25. The top of the over-pressured
zone is shown at the depth where the
shale transit time deviates from thenormal trend.
Fig. 25: Over-pressure shown by
the Sonic log
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Formation Evaluation 7. Source Rock Identification.
The presence of organic matter in shales lowers the sonic velocities, apparently in direct
relationship to abundance. If, therefore, sonic velocities are cross-plotted against another
diagnostic log, such as the resistivity log, organic rich zones may be identified.
8. Seismic Applications of the Sonic Log.
Sonic and Seismic Velocities.
The sonic log can distinguish beds as thin as 50 cm, while the seismic wave can resolve
beds of 10 m at shallow depth, but is limited to beds of about 50 m in deeper sections. The
resolution of the sonic log is, therefore, about 100 times better than the resolution of the
seismic trace.
To compare sonic log and seismic data, the sonic log data must be averaged over large
intervals, to the same scale as the seismic data.
Sonic Logging
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Formation Evaluation Interval Velocities.
Fig. 26: Interval Velocity graph andtime-depth curve.
S ynthetic Seismograms.
A synthetic seismogram is the presentation of the sonic log in the form of a seismic trace.
It involves the replaying of the high frequency sonic log data at the low frequency of the
seismic data.
The seismic section is a record of the acoustic reflections from subsurface boundaries,
which depend on the contrast of the acoustic impedances of adjacent formations.
The acoustic impedance is the product of the velocity and the density, V x D, and the
reflection coefficient, R, is:
acoustic impedance lower zone - acoustic impedance upper zone
R =
acoustic impedance lower zone + acoustic impedance upper zone
D2V2 - D1V1
or: R =
The result of sonic logs for use with
seismic interpretation may be given in
the form of an average intervalvelocity curve, and as a time-depth
curve.
The average sonic interval velocity is
obtained by counting the integrated
travel time marks over the interval
under study, and dividing this value by
the length of that interval.
The time-depth curve is obtained by
accumulating the interval velocitiesand then plotting the accumulated
milliseconds against depth.
An example of a sonic interval
velocity graph, and the related time-
depth curve are presented in Figure 26.
The sonic interval transit time for each
interval, in this example, is given in
brackets in the depth column.
D2V2 + D1V1
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Formation Evaluation When both the sonic log and the density log are run in the well, the acoustic impedances of
the layers can be calculated.
The acoustic impedance log shows the logged section as it would be sensed by the seismic
pulse.
Fig. 27: Schematic diagram of the construction
With the aid of a computer, a
synthetic seismic signal is
formulated and passed through the
acoustic impedance log.
The seismic signal is distorted in
the same way as if it were going
through the layers in the
subsurface.
Recording these distortions, the
computer then constructs a
synthetic seismogram.
A schematic presentation of the
construction of a synthetic
seismogram is shown in Figure 27.
of a synthetic seismogram.
(D,H, Thomas, 1978)
SONIC LOG
Purpose.
To measure the velocity of a sound pulse through a formation.
Principle.
A transmitter emits a sound wave which spreads in all directions. The fastest wave, the
compressional wave, is detected by two receivers. The difference in arrival time of the
compressional wave at the two receivers is recorded and is called the interval transit time,
delta T.
Sonic Logging
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Sonic Logging
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Formation Evaluation Uses.
Porosity determination.
Well to well correlation.
Lithology identification.Texture determination.
Fracture identification.
Compaction studies.
Over-pressure detection.
Source-rock identification.
Seismic applications.
Advantageous Characteristics.
Can be used in all types of mud.There is hardly any borehole effect.
There are no restrictions on the logging speed.
Combination with other tools is possible.
Limitations.
In air-filled holes, or if the mud is gas-cut, the attenuation of the sonic signal is too high to
allow detection of the first arrival.
In gas-bearing formations, or even in oil zones, the interval transit time may be too high.
If the interval transit time in the virgin zone is lower than in the flushed zone, or an altered
zone around the borehole, no formation transit time can be obtained.