describes complete flow chart

1. SEISMIC INTERPRETATION WORK FLOW
PRESENTED BY : GROUP 03
GEOPHYSICS

2. SEISMIC INTERPRETATION WORK FLOW
CONVENTIONAL SEISMIC
INTERPRETATION
UNCONVENTIONAL SEISMIC
INTERPRETATION
Synthetic Generation Tie Wells With
Seismic
Horizon Interpretations
Fault Manual Picking
Determine Seismic Interpretations Target
Created Data Condition Workflow
Generated Seismic Attributes
STRUCTURE
• Edge Attributes
• Curvatures Attributes
• High Window Length Horizontal &
Vertical
STRATIGRAPHY
• Physical Attributes
• Edge Attributes
• Small Horizontal & Time Window
STRUCTURE IDETIFY :
FAULT , SALT , GAS , CHIMENY
DHI (direct hydrocarbon
Indicator)

3. SEISMIC INTERPRETATION
“The science of inferring the geology at some depth from the processed seismic record”
(American Association of Petroleum Geology (AAPG))
Seismic Interpretation is the extraction of
subsurface geologic information
from seismic data.
Seismic data is collected and worked through
several models to produce useful information
.The goal is a reduction in exploration and
development risk of drilling for hydrocarbons

4. Seismic interpretation is broadly divided into two different techniques :
 1. Conventional Seismic Technique
 2. Unconventional Seismic Technique
CONVENTIONAL SEISMIC TECHNIQUES
Conventional or traditional seismic techniques also
known as qualitative interpretation, the primary aim of
which is to map subsurface geology . It includes the
marking of laterally consistent reflectors and
discontinuous characteristics like faults of various types
and their mapping on different scales . The geometry on
the seismic section is precisely interpreted in view of the
geological concepts to detect the hydrocarbon
accumulation . The structural and stratigraphic
architecture of the petroleum system is determined on the
behalf of the geometric features the location of a well
established.

5. UNCONVENTIONAL SEISMIC TECHNIQUES
Unconventional or the quantitative seismic techniques from the previous two decades proved itself
more useful than the traditional, in which the physical variation of the amplitudes is considered to
predict the hydrocarbon accumulation . Variation alterations of the amplitudes techniques have
contributed to better prospect evaluation and reservoir characterization . Particularly, the
unconventional techniques widen the exploration areas. They validate hydrocarbon anomalies and
make prospect generation easier

6. Conventional Seismic Techniques further divided :
SYNTHETIC GENERATION TIE WELLS
WITH SEISMIC
Seismic-well tie The seismic waveform can be interpreted as geology after we
link the waveform “wiggles” to well-log-based synthetics. This process is
often called the seismic-well tie. The seismic-well tie is the starting point for
both QI and structural interpretation. A seismic-well tie offers many benefits ,
1. It provides a basis for interpreting seismic events in geologic terms.
2. It helps establish a time-depth relationship between seismic data and
the well depths, respectively.
3. It generally requires the estimation of a wavelet and therefore the phase
of the data.
4. It enables general quality control of both seismic and well logs.
5. It enables the understanding of seismic resolution and tuning effects.

7. The quality and usefulness of seismic-well ties can be impacted by various factors. Generally, it is
desirable to have “tall” logs that penetrate much of the overburden, if not also below a reservoir zone
of interest. This is because the ability to generate good well-ties over a tall section helps to build
confidence in the overall interpretation. Accurate synthetic amplitudes generally require P-wave sonic
log and density log data. For a non-vertical incidence angle synthetic, we also require S-wave sonic
log, but these are often not recorded. A possible mitigation step that can be taken in this case is to
generate pseudo-shear logs. Well log quality, and hence seismic-well tie quality, may also be
influenced by down hole logging conditions such as hole rugosity and wash out.
Well to seismic ties is a fundamental step in seismic interpretation. It relates subsurface
measurements obtained at a wellbore measured in depth and seismic data measured in time. A time-
depth relationship is typically computed by integrating the slowness function measured at a wellbore

8. STACKING VELOCITIES DERIVED FROM SEISMIC DATA
These provide the poorest time-depth control.
There are several reasons for this, such as the
processors’ need to avoid multiples and the
limited offsets of real seismic data. Stacking
velocities are essential in frontier plays where
other data do not exist
VELOCITY SURVEYS AND VERTICAL SEISMIC PROFILES
(VSP)
VSP give the best velocity control. They use a surface source and geophones
downhole. The check shot uses “first breaks” (first reception of energy downhole
after the shot), while the VSP analyzes the full sonic waveform over more closely-
spaced geophone positions. If the first breaks are detectable, compression wave (P-
wave) time vs. depth is determined as accurately as possible.

10. Seismic Horizon Interpretation
Horizon interpretation is one of the key steps of locating reservoirs and well
placement. Interpreters track horizon surfaces according to the amplitude, phase, and
continuity patterns of seismic events. Horizon picking on a dense grid for a
3D seismic survey is a time-consuming task.
Reflection seismic is one of the fundamental way of imaging the
subsurface from a geological perspective. 2D and 3D seismic data are
major sources of information in the oil industry for both onshore and
offshore activities.
The amplitude of a seismic horizon will depend on the impedance
contrast of the geological layers that define that horizon. When there is a
large contrast of impedances, the absolute value of the amplitude of the
corresponding reflector will be high (will have a high absolute value of
reflectivity) . The best example is the seabed, where the low impedance
of sea water and the much higher impedance of sediments will originate
what is referred to as a ‘very bright’ reflector, with very high amplitudes.

11. Horizon Interpretation Techniques
Seismic horizons can be interpreted in 2D lines or in 3D volumes. There are numerous interpretation techniques that can be
used, depending on the data and software available. However, after the initial quality control check of the data is made, the
polarity noted and the existing wells displayed, the general steps are as follows:
Define the horizon to be interpreted. This could be a top defined in the wells, based on lithostratigraphy or biostratigraphy; an
unconformity; reservoir top or base; or another event that is visible on seismic. The definition of the concept of what is being
interpreted is important when doubts arise on which reflector to follow in the interpretation, or whether the horizon’s extension
is limited or not or similar issues.
It is recommended that at least the main faults are interpreted. Small throws can be easily perceived and do not greatly affect the
horizon mapping, but larger throws can originate mis-ties and erroneous interpretations.
Start the interpretation from a point where you are sure of what you are interpreting – a top in a well or a seismic section with
clear imaging and geometry.
Define an interpretation spacing and interpret inlines and crosslines in a regular grid. The standard for 3D is to pick every 25
lines, but it can be tighter if more detailed mapping is needed or more spaced if you are working on a regional mapping project.
In 2D data, all relevant lines should be mapped.
Regular quality control checks should be carried out between inlines and crosslines, to avoid mis-ties.
With 3D data the filling of the mapped grid spaces can be done by propagation or tracking; i.e., by getting the programme to
automatically follow the mapped horizon, which all interpretation programmes allow. It can be undertaken in one go for the
entire area, but it is recommended that it is done in portions to control the quality of the tracking. Seismic interpretation software
has improved greatly over the years, with more ‘geological’mapping algorithms, but human control is still key to ensuring
reliable results.
At the end of the propagation it is likely that there will still be spaces that are not interpreted, due to poor quality seismic, locally
different seismic facies or other factors. Only in this situation, when it is impracticable to fill all spaces manually, should an
interpolation (gridding) be made, which follows the mapped horizon rather than the seismic data. With 2D data, interpolation of
the mapped horizon is the only way to obtain a 3D object.

12. SEISMIC STRUCTURAL INTERPRETATION (major and minor faults)
The original use of seismic reflection data (circa 1930 through 1960) was to create maps depicting the geometry
of a subsurface structure. Because many of the world’s largest oil and gas fields are positioned on structural
highs, structural mapping has been, in a historical sense, the most important application of exploration seismic
data. When the seismic industry converted from analog to digital data recording in the mid-1960s, digital
technology increased the dynamic range of reflected seismic signals and allowed seismic data to be used for
applications other than structural mapping, such as:
• Stratigraphic imaging
• Pore-fluid estimation
• Litho facies mapping
These expanded seismic applications have led to the discovery of huge oil and gas reserves confined in
subtle stratigraphic traps, and seismic exploration is now no longer limited to just “mapping the structural
highs.” However, even with the advances in seismic technology, structural mapping is still the first and most
fundamental step in interpretation. When 3D seismic data are interpreted with modern computer workstations
and interpretation software, structural mapping can be done quickly and accurately.
Different seismic interpreters use different approaches and philosophies in their structural interpretations. The
technique described here is particularly robust and well documented. The first step of the procedure is to convert
the 3D seismic data volume that has to be interpreted to a 3D coherency volume. Coherency is a numerical
measure of the lateral uniformity of seismic reflection character in a selected data window. As the waveform
character of side-by-side seismic traces becomes more similar, the coherency value for the traces approaches a
value of +1.0; as the traces become more dissimilar, the coherency of the traces approaches zero. All modern
seismic interpretation software can perform the numerical transform that converts 3D seismic wiggle-trace data
into a 3D coherency volume.

13. The second step of the structural interpretation
procedure is to transfer the fault pattern defined by
coherency data to the associated 3D seismic wiggle-
trace data volume. illustrates the projection of the
faults in onto a vertical profile through 3D seismic
image space. The coherency time slice defines the X,
Y coordinates of each intersected fault at one
constant, image-time coordinate across the image
space. Additional coherency time slices are made at
image-time intervals of 100 or 200 milliseconds to
define the X, Y coordinates of each fault as a
function of imaging depth. This procedure causes the
orientations and vertical extents of faults transferred
to a 3D seismic wiggle-trace volume to be quite
accurate. The first-order fault labeled in extends
through the entire stratigraphic column and create
large vertical displacements of strata. The second-
order faults have less vertical extent and cause less
vertical displacement than the first-order faults.
Other structural and stratigraphic features that are
common in Gulf of Mexico geology are labeled.

14. These features are identified to indicate the imaging capabilities of seismic data. Rollover indicates fault-
related flexing of bedding, which results in structural trapping of hydrocarbons. The bright spot is an example
of reflection amplitude reacting as a direct hydrocarbon indicator (see changes in pore fluid . The velocity sag
feature is a false structural effect caused by anomalously low seismic propagation velocity that delays
reflection arrival times, leaving the misleading appearance of a structural sag. The third step of this approach
to structural mapping is to interpret a series of chronostratigraphic surfaces across the seismic image space.
These surfaces can be any of the chronostratigraphic surfaces (flooding surfaces, maximum flooding surfaces,
and erosion surfaces) described in Sec. 2.15, depending on the amount and quality of subsurface well control
available to the interpreter . If there is no well control, interpreters must use their best judgment as to how to
correlate equivalent strata across a seismic image space and then adjust their interpretation, if necessary, as
wells are drilled.
When a selected stratal surface is extended across the complete seismic image space, the geometrical
configuration of that chronostratigraphic surface can be displayed as a structure map. The structure map is
one of the chronostratigraphic surfaces interpreted across this Gulf of Mexico prospect with the fault
geometry information defined by coherency slices and vertical slices . The producing fields shown in the map
are positioned on local structural highs associated with one or more first-order faults.

16. UNCONVENTIONAL SEISMIC INTERPRETATION further divided :
SEISMIC INTERPRETATION TARGET
Data preconditions for unconventional seismic attributes
interpretation Data preconditions workflow has been applied to
enhance seismic data by QC the data for determination of
spectral frequency and amplitude range and check frequency of
noise and its amplitude, then apply band pass filter to remove
frequency of low and high frequency, after that smooth mean
filter has been applied. To obtain the best and accurate results
from seismic data first step preparing seismic data to enhance
seismic attributes results, spectral analysis help to determine the
noise effect in seismic data and can give actual view about
frequency and amplitude relations. In this case study first we
made spectral analysis for the whole cube to determine
frequencies bandwidth for the interested seismic signals and
noises frequencies. Band pass filter enhances signal to noise ratio
by removing noises in the lower and higher frequency ranges and
enhance data continuity. After applied band pass filter the
reflectors continuity increases and high frequency noise reduces

17. DATA CONDITION WORKFLOW
Three steps have been generated in this work for effective data preconditions techniques:
1) Seismic data quality control by spectrum analysis relation between frequencies and
amplitude in 3D seismic cube we can determine interested bandwidth frequencies,
2) Band pass frequencies filter to remove low and high noise frequencies,
3) Overcome random noises by smooth mean filter, the mean filter is a low-pass filter
that typically is implemented as a running window-average filter.

18. SEISMIC ATTRIBUTES
 Seismic attributes are the components of the seismic data which are obtained by
measurement, computation, and other methods from the seismic data. Seismic
Attributes were introduced as a part of the seismic interpretation in early 1970’s.
 Any information of interest that can be derived from seismic is ‘Seismic Attributes’.
Classification of Seismic Attributes
The Seismic Attributes are classified basically into 2 categories.
1. Physical Attributes
2. Geometric attributes
PHYSICAL AND GEOMETRICAL ATTRIBUTES
 Physical attributes are defined as those attributes which are directly related to the wave
propagation, lithology and other parameters.
 These physical attributes can be further classified as pre-stack and
post-stack attributes.
 The Geometrical attributes are dip, azimuth and discontinuity. The Dip attribute or
amplitude of the data corresponds to the dip of the seismic events

19. MAINLY USEFUL IN IDENTIFYING
 Bright spots
 Gas accumulation
 Sequence boundaries, major changes or depositional environments
 Thin-bed tuning effects
 Major changes of lithology
 Local changes indicating faulting
 Spatial correlation to porosity and other lithological variations
 Event terminations
 Picked horizons
 Fault detection
 Zones of parallel bedding
 Non-reflecting zones
 Converging and diverging bedding patterns
 Unconformities

20. POSSIBLITY OF RESERVOIR
Seismic data that ca be used to determine the possibility of reservoir are as follows :
 Well data such as logs typically provide sufficient vertical resolution but leave a large space between
the wells.
 Three-dimensional seismic data, on the other hand, can provide more detailed reservoir
characterization between wells. However, the vertical resolution of seismic data is poor compared of
well data.
 Information such as porosity, p-wave velocity, shale volume, water saturation, permeability, lithology,
and production zones can be obtained from the processing and interpretation of well logs.
Migration
The hydrocarbons migrate according to the law of buoyancy through porous rocks.
Traps
A trap consists of an impervious stratum that overlies the reservoir rock thereby prohibiting hydrocarbons
from escaping upward and laterally. This impervious stratum is called a roof rock; it intervenes to collect
and hold hydrocarbons underground.

21. Types of reservoir :
1) Structural trap 2) Stratigraphic trap

23. DIRECT HYDROCARBON INDICATORS(DHIs)
A hydrocarbon indicator (HCI) or direct hydrocarbon indicator (DHI), is an anomalous seismic
attribute value or pattern that could be explained by the presence of hydrocarbons in a oil or gas
reservoir. DHIs are particularly useful in hydrocarbon exploration for reducing the geological risk of
exploration wells.
Broadly, geophysicists recognize several types of DHI :
 Bright spots
 Flat spots
 Dim spots
 Polarity reversal
BRIGHT SPOTS
High amplitude that can indicate the presence
of hydrocarbons. Bright spots result from large
changes in acoustic impedance and tuning
effect, such as when a gas sand underlies a
shale

24. DIM SPOT :
A type of local seismic event that, in contrast to a bright
spot, shows weak rather than strong amplitude. The
weak amplitude might correlate with hydrocarbons that
reduce the contrast in acoustic impedance between the
reservoir and the overlying rock, or might be related to
a stratigraphic change that reduces acoustic impedance.
FLAT SPOT :
A flat spot is a seismic attribute anomaly that appears
as a horizontal reflector cutting across the
stratigraphy elsewhere present on the seismic image.
Its appearance can indicate the presence of
hydrocarbons. Therefore, it is known as a direct
hydrocarbon indicator and is used by geophysicists
in hydrocarbon exploration.

25. POLARITY REVERSAL
Polarity reversal or phase change is a local amplitude seismic attribute anomaly that can indicate the
presence of hydrocarbons and is therefore known as a direct hydrocarbon indicator. It primarily results
from the change in polarity of the seismic response when a shale (with a lower acoustic impedance)
overlies a brine-saturated zone (with a high acoustic impedance), that becomes invaded with an oil/gas
sand (with the lowest acoustic impedance of the three). This changes the acoustic impedance contrast
from an increase to a decrease, resulting in the polarity of the seismic response being reversed.
Example:
Reversal of polarity associated with bright spots caused by gas in the unconsolidated sand of the Gulf of Mexico.

26. THE END