well to Seismic Interpretation

1. This presentation includes forward-looking statements. Actual future conditions (including economic conditions, energy demand, and energy supply) could differ materially due to changes in technology,
the development of new supply sources, political events, demographic changes, and other factors discussed herein (and in Item 1A of ExxonMobil’s latest report on Form 10-K or information set forth
under "factors affecting future results" on the "investors" page of our website at www.exxonmobil.com). This material is not to be reproduced without the permission of Exxon Mobil Corporation.
This presentation includes forward-looking statements. Actual future conditions (including economic conditions, energy demand, and energy supply) could differ materially due to changes in technology,
the development of new supply sources, political events, demographic changes, and other factors discussed herein (and in Item 1A of ExxonMobil’s latest report on Form 10-K or information set forth
under "factors affecting future results" on the "investors" page of our website at www.exxonmobil.com). This material is not to be reproduced without the permission of Exxon Mobil Corporation.
Integrated Well – to – Seismic
Interpretation
Olusegun Akintayo

2. Objectives
After this lecture you should understand:
•The importance of integrated well-to-seismic interpretation
•The basic well-to-seismic interpretation process & workflow
•Well-to-seismic interpretation tips, tricks & common pitfalls
Well
Seismic versus… Well
Seismic

3. Outline
• What is Integrated well-to-seismic interpretation?
• Why is Integrated well-to-seismic interpretation
important?
• What Data is Needed for an Integrated well-to-
seismic interpretation?
• Integrated well-to-seismic interpretation strategy
• Integrated well-to-seismic interpretation workflow?
• Summary

4. • How geology, as
found in a
wellbore, is
characterized on
the seismic data at
the well location
• Relates well logs
measured in depth
to seismic data
measured in time
What is Integrated Well-to-Seismic Interpretation

5. Why is Integrated Well-to-Seismic Interpretation Important?
• Correlating seismic interpretations and well picks
– “What event should I follow on the seismic to map this sequence boundary?”
– “What does my reservoir look like on the seismic?”
• Understanding your seismic data
– “What are the phase and polarity of my seismic?”
• Time to depth conversion
– “What TD polynomial should I use around my well?”
• Real-time monitoring of drilling
– “When should we start coring?”
• Where is the bypassed opportunity
– “What does the opportunity look like on seismic?”
– “Can fluid contacts seen in the well be identified on the seismic?”
• Reservoir Connectivity
– “How are my reservoirs connected?”
– “Can the baffles or barriers be seen on seismic?”

6. Data Needed for an Integrated Well-to-Seismic Interpretation
• Sonic Log
• Density Log
• Deviation Survey
• Wavelet
• Time-Depth Relationship
• Other Data
– Cores
– Pressure Data
– Production / Performance History

7. Sonic Log
Borehole Compensated
Sonic Tool
Basic Sonic Tool
Slowness = dt = 1 / Vinterval = Time(us) /
Distance(ft)
Slowness = [ (a+b+c) – (a+d+c) ] / L = (b-d)/L
a
b
d
c
c
T
R1
R2
L
Measured slowness is
independent of
changes in borehole
diameter (e.g.,
washout, bit size)
Equivalent to a
small-scale seismic
refraction survey
along the borehole
wall
UT
LT
R1
R2
R3
R4
Common Curve Mnemonics (Names)
•Compressional Sonic: DT, DTC, DTCO, DT4P
•Shear Sonic: DTS, DTSM, DT1, DT2
Sonic tools measure transit time (DT) from source(s) to receivers, not velocity of rocks

8. Density Log
• Most reliable source of porosity provided good
pad contact is maintained.
• Can be used with neutron porosity to estimate
porosity and identify gas zones.
• Wireline bulk density is reduced in gas zones, in
washouts where pad contact is not maintained,
and when the tool pad is rotated away from the
borehole wall.
Common Curve Mnemonics (Names)
• RHOB, RHOZ, DENS
Bulk density tools estimate combined density of the rock and fluids from
gamma ray reduction between source and receiver

9. Deviation Survey Data
• Required to correctly position
data in deviated wells
• Never assume well loaded
correctly
• Common Problems
– Incorrect datum
– Incorrect surface well location
– Incorrect deviation (XY loaded
as YZ data)
– Seismic image location not
actual location (under or over
migrated data)
– Wrong geodetics
• Confirm digital survey data
agrees with printed report

10. Wavelets
• A wavelet (in our context) is a seismic pulse that represents the
seismic reflection response at a single impedance boundary
• The wavelet that is representative of your specific seismic data is
a function of
– Acquisition
– Earth
– Processing
• Characteristics of a wavelet are
– Polarity
– Phase
– Amplitude spectra (frequency content)
• To make a well tie, you should use a wavelet with same or
similar characteristics as the seismic data you are tying to

11. Wavelet Sources
• Analytic or “Canned” (Ricker,
Butterworth, etc.)
– Simple to generate and is often all that is
needed to make a good tie
– Estimate peak frequency by counting
cycles or extracting amplitude spectra
from data
• Extracted
– Statistical – assumes phase & polarity
– Deterministic – assumes time-depth
correct
• Modeled
– Higher effort – not common for making a
well-tie
– Example: deterministically matching
acquisition & processing parameters
When choosing a wavelet, start simple and add
complexity if needed

12. Time – Depth Relationship
• Well logs (geology) are measured in depth
• Seismic is measured in time (normally two-way time)
• To relate well logs (and the synthetic seismogram) to
seismic requires a time-depth function, commonly
referred to as the checkshot or time-depth pairs

13. Sources of Time-Depth Function
• Checkshots
• Measure the vertical one-way time from surface to various depth
stations (levels) within the well
• Time-depth pairs
• Used to determine start time of top of well log
• Vertical Seismic Profile (VSP)
• Similar to checkshots but many more receiver positions and
receivers are 3-component
• Can be processed to produced near borehole seismic image
• Sonic data measures transit time (DT) over a known
distance
• Travel time to a depth in the well can be found by
summing (integrating) the individual DT
measurements down to that depth
• Integrated sonic time to a particular depth will
typically be different than that obtained by a
checkshot
• Tools investigate different volumes of rock
• Instrumental errors & analysis inaccuracies
• Different wave propagation characteristics
• Checkshot values are used to correct this “drift”
inherent in integrated sonic

14. Integrated Well-Seismic Interpretation Strategy
Impedance and Reflectivity
• Impedance (I) = Velocity * Density
• Seismic energy will be reflected at an impedance boundary (I1 ≠ I2)
• The magnitude of the reflected energy or reflection coefficient (RC) depends on
the magnitude of the impedance contrast (larger contrast = stronger reflection)
• The sign or polarity of the RC depends on whether I1 > I2 or I1 < I2
• This is easily seen in the equation for a zero-offset (normal incidence) RC, where
offset refers to the distance between source and receiver

15. How to Generate a Zero-Offset RC Series

16. Convolution With the Wavelet

17. Integrated Well-to-Seismic Interpretation Workflow

18. Integrated Well-to-Seismic Interp.
Tips, Tricks & Pitfalls

19. Summary
• Integrated well-to-seismic
interpretation provide a link
between well and seismic data
• Well ties are an integral part of
your subsurface interpretation
• Start simple; Use a fit-for-purpose
approach to making well-to-seismic
interpretation
• Understand your data
• Data QC is critical
• Logs
• Seismic
• Checkshot/Deviation
• Wavelets
Do No Harm!

20. Discussion
Ideas / Questions

21. Thank You
for
Listening