A Case Study on Time-To-Depth Conversion Using Seismic and Well Logging Data

7/27/2019 A Case Study on Time-To-Depth Conversion Using Seismic and Well Logging Data

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SPG/SEG Shenzhen 2011 International Geophysical Conference Technical Program Expanded Abstracts

A case study on time-to-depth conversion using

seismic and well logging data

Guo Jianming Ling Yun Guo Xiangyu(BGP, CNPC, CHINA)

Summary: The precision and consistence of the information interpreted from seismic data in the time

domain and from logging data in the depth domain contribute to the capability of reservoir characterization

with integration of seismic and well logging data. It is very important to obtain accurate conversion from the

time domain to the depth domain. Therefore, based on chronohorizons in well and seismic data, this paper

indicates that discrepancies in the time-to-depth conversion can be reduced to less than 2 meters at the

chronohorizon by horizon-based seismic velocity analysis, well-seismic velocity calibration, well-seismic

datum correction, joint well-seismic interpretation, and well-seismic spatial remaining velocity correction,

which has laid a solid foundation for the joint well-seismic reservoir characterization.

Key word: Reservoir characterization; Time-to-depth; Chronohorizons; Seismic velocity; Average velocity

1 Introduction

The time-to-depth conversion (TDC) and

structural mapping of seismic data are a

geologist's greatest concerns in seismic

exploration. Based on the different assumptions

in the velocity change versus the formation depth,

seismic travel time calculation and the least

squares of TDC were presented by Slotnick

(1936) and Legge and Rupnik (1943),

respectively. Doherty and Claerbout (1976)

studied the dependence of velocity on structure

with a non-horizontal layer, which laid the

foundation for velocity modeling and depth

imaging. From there, May and Covey (1981),

Bishop et al. (1985) and other researchers studied

the case in which velocity varies spatially and

proposed many techniques for TDC, which

improved the precision of TDC under conditions

of complex geological structures. In addition,

Homby et al. (2006) introduced a field case for

3D VSP and 3D seismic depth migration, and

obtained satisfactory imaging in the subsalt dome.

With the development of the time-to-depth

conversion for seismic data, we can see that the

precision meets the requirements for structure

interpretation, but is still insufficient for

reservoir characterization. Therefore, the TDC

precision needs to be improved.

Reservoir modeling and simulation

generally require that the depth error of TDC be

less than one meter. To meet the needs for TDC

precision in reservoir characterization, we

present a TDC procedure based on the

chronohorizons, which including horizon-based

seismic velocity analysis, well-seismic velocity

calibration, well-seismic datum correction, joint

well-seismic interpretation, and so on. The

chronohorizon must meet the following

conditions: 1) it must be relatively isochronous in

geologic age; 2) it must be observed in the

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velocity calibration requires the statistical

time-velocity relationship from the logging data.

For each reference interface of each well using

the reflection time of the chronohorizon from the

seismic results and the corresponding depth value

from logging, we can calculate the average

velocity, shown as the yellow dots in Figure 2a.

Figure 2b shows the well and seismic fitted

velocity computed using Formula 1; the fitted

curve can be used to calibrate seismic velocity.

Comparison of corrected velocity with original

velocity indicates that the shifting trend of the

calibrated velocity versus time comes along withthe well-seismic fitted velocity (Figure 2c).

)1(2,1;2,1)](1/2[1 1

2

0

M

j

N

i

iii ji zvt z

i z it

0v

Where is well top in depth, is seismic time

corresponding to the well top, i is the well

number, j is the horizon number, and and

are the match parameters of fitted velocity and

time by the well-seismic integration.

The macro velocity correction using the

above process can significantly reduce the

difference between well logging and seismic

velocity, and can eliminate the impact of VTI

anisotropic media. The final depth error reduces

from an average 9.11meters without the velocity

correction (column 3 in Table 1) to an average

4.6meters with the velocity correction (column 4

in Table 1).

2.3 Well-seismic Datum Correction

Usually there is a difference between the

well logging datum and the datum used for

seismic imaging. This difference can be ignored

for seismic exploration. However, it may

seriously affect the accuracy of the reservoir

model in the reservoir characterization stage.1500 2000 2500 3000

1500 2000 2500 3000

veolicity

0

4 0 0

8 0 0

1 2 0 0

1 6 0 0

2 0 0 0

0

4 0 0

8 0 0

1 2 0 0

1 6 0 0

2 0 0 0

t i m e

Calibrated seismic velocity

Original seismic velocity

Fitting curve

Legend

Velocity

D89

D67

D53

D83

T i m e

(a)

Velocity

T i m e

(b)

(c)

Fitting function( , )0v

Velocity

T i m e

Figure 2: Well-seismic joint velocity difference

correction.

WellOriginal New Macro-

correct

Datum Joint

interpret

Remaining

correctSeismic-V Seismic-V correct

67-39 12.37 10.43 5.43 2.87 2.87 0.74

30-143 11.36 -1.39 -5.99 1.99 1.99 -0.34

67-45 8.91 10.38 7.27 -0.51 -0.51 -1.72

D177 12.7 9.36 2.99 2.99 2.99 0.99

57-43 11.85 12.03 5.83 2.4 2.4 0.17

62-148 10.37 11.57 7.69 1.05 1.05 -0.74

51-41 11.08 14.23 8.08 2.39 2.39 0.03

35-50 16.33 16.15 13.91 0.88 0.88 0.02

52-146 11.46 7.08 2.16 2.16 2.16 -0.15

56-150 13.3 14.89 5.42 1.33 1.33 -0.88

48-144 11.85 8.19 3.25 3.25 2.05 0.83

D67 11.95 8.38 2.44 2.44 2.44 0.46

44-144 10.33 11.36 6.76 1.9 1.9 -0.39

56-154 12.73 10.79 3.15 3.15 2.25 0.81

48-156 11.83 11.06 5.79 2.52 2.52 0.18

D84-s4 9.41 4.46 -0.03 -0.03 -0.03 -0.79

40-154 10.5 6.29 1.45 1.45 1.45 -0.55

D205 10.9 9.28 3.6 1.91 1.91 0.0848-166 8.66 10.41 6.44 2.05 2.05 -0.31

67-83 9.49 4.21 0.67 0.67 0.67 -0.06

46-166 11.99 10.51 3.24 3.24 2.14 0.84

40-162 11.4 7.43 1.95 1.95 1.95 -0.14

36-162 10.75 7.56 1.82 1.82 1.82 -0.11

039-43 9.55 7.58 1.19 1.19 1.19 0.49

36-166 11.36 8.23 2.06 2.06 2.06 0.15

47-75 11 7.37 2.31 2.31 2.31 0.22

52-148 5.82 5.44 -13.39 2.39 2.39 0.46

Average 11.08 9.11 4.60 1.96 1.84 0.47

Table1: The stepwise decreasing error of TDC at the

top of the reservoir

(a) Velocity vs. time along wellbore. (b) Fitted velocity curve (blue)

of well and seismic data. (c) Comparison between original seismic

velocity and calibrated seismic velocity pre/post seismic correction

and well-seismic fitted curve. Shifting trend of calibrated velocity

(red) is consistent with that of well-seismic fitted velocity (orange).

The well-seismic datum correction

procedure takes place after all the steps

mentioned above. The results before well-seismic

datum correction are shown in Figure 3a. In this

figure, the cross-plot of time versus velocity

before the well-seismic datum correction is

shown on the left hand side. The map of depth

error is shown in the middle and the seismic

profile overlapping well logs in depth is shown

on the right hand side. The corresponding results

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after well-seismic datum correction are shown in

Figure 3b. Comparing Figure 3a with Figure 3b,

it is clear that the isolated points (shown in red

circle in Figure 3a) where there are large errors

in the scatter plot and the map disappeared after

the well-seismic datum correction. The distance

between seismic horizon and corresponding well

top becomes smaller. The depth error, which was

less than 13 meters before processing (Table 1,

4th

column), is now reduced to less than 4 meters

(Table 1, 5th

column).

2.4 Well-seismic Interpretation Calibration

After completing the well-seismic datumcorrection as discussed above, the isolated error

points shown in the middle of Figure 3b still

exist. The error of these points usually stems

from the interpretation error of seismic horizons

and the reservoir well tops. Therefore, it is

necessary to combine the well and seismic

interpretations. Figure 3c shows the results after

well-seismic joint interpretation. Comparing

Figures 3b and 3c, we see that the scatter points

extracted along the wellbore in the scatter plot

are more concentrated, and the depth error in the

map is further reduced. In addition, the distance

between the seismic horizon and the

corresponding well top is also reduced. Besides,

Table 1 shows that the error is reduced from less

than 4 meters (Table 1, 5

th

column) to less than 3meters (Table 1, 6

th column) after well-seismic

joint interpretation.

(b)

(a)

(c)

-8

-6

-4

-2

0

2

4

6

8

Residual

Velocity

Velocity

Velocity

T i m e

T i m e

T i m e

Reservoir top

Middleinterface

Reservoir bottom

The position map of stream cavity

1) Well-seismic datum correction

2)Well-seismic joint interpretation

well1 well2 well3 well4 well5 well6

Figure3: Quality control of well-seismic datum correction and joint interpretation.

(a) Before datum correction, (b) after datum correction, and (c) after well-seismic joint interpretation. In this figure, the cross-plot of time

versus velocity before the well-seismic datum correction is shown on the left hand side of (a), (b), and (c). The map of depth error is shown in

the middle and the seismic profile overlapping well logs in depth is shown on the right hand side of (a), (b), and (c). After the well-seismic

datum correction and well-seismic joint interpretation, the depth error becomes smaller on reservoir top and middle interface, but is relatively

bigger on reservoir bottom. The reason for this is that seismic imaging is affected by stream inject ion during the reservoir development stage

and results in interpretation error at re servoir bottom, which is not discussed in this paper .

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2.5 Remaining Error Correction

After all the steps discussed above, the

depth error has been decreased to about 2 meters

(Figure 4a or Table 1, 6th

column). Nevertheless,

it still does not meet the requirements for

reservoir characterization and further processing

is needed. Figure 4a shows that the remaining

error is randomly distributed. The velocity

correction factor of the remaining error shown in

Figure 4c is used to smooth the random error.

Comparison of Figures 4a and 4b shows that the

spatial random error is reduced to less than 1

meter. The range of correction factor increased

from 0.995 ~ 1 (Figure 4c) to 0.999 ~ 1 (Figure

4d). Finally, the calibrated seismic velocity is

very close to the well velocity in space. From the

above analysis, we conclude that the final depth

error can be reduced to less than 2 meters (Table1,

7th

column). This can basically satisfy the

precision requirement for reservoir modeling and

simulation.

(a) (c)

(b) (d)

Figure 4: Quality control of depth error correction

(a)Before calibration and (b) after calibration. (c) The remaining factor map before calibration and (d) after calibration. The remaining

depth error is reduced after calibration and the scale of the correction factor is increased to from 0.995~1 to 0.999~1, which indicates

that the final seismic velocity is very close to the well velocity.

3 ConclusionsWell-seismic TDC directly affects reservoir

interpretation and the model accuracy. We

introduce in this paper a TDC technique based on

the chronohorizon, which includes horizon-based

seismic velocity analysis, well-seismic velocity

calibration, well-seismic datum correction, joint

well-seismic interpretation, and well-seismic

spatial remaining factor correction. This

technique has been verified with field data and

the final depth error of TDC is less than 2 meters,

satisfying the requirements for reservoir

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A Case Study on Time-To-Depth Conversion Using Seismic and Well Logging Data

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