Section 11 - Sonic Logging

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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)

Sonic Logging

Issued Oct 2003 Theo Grupping




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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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.

Sonic Logging





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.

Sonic Logging





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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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],

Sonic Logging





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.

Sonic Logging





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.

Sonic Logging





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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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.

Sonic Logging






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.

Sonic Logging






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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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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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





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




Sonic Logging


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.

Section 11 - Sonic Logging

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