Seismic interpretation, whether for hydrocarbon exploration or geotechnical studies, is the determination of the geological significance of seismic data. It is rare that the correctness (or incorrectness) of an interpretation can be ascertained, because the actual geology is rarely known in enough detail. Instead, the test of a good interpretation is consistency with all of the available data. In oil and gas exploration, emphasis is placed on finding an interpretation that is most favourable for hydrocarbon accumulation. As with many scientific investigations, interpretations are almost always non-unique.

Petroleum Geology - Basic Concepts:
    -Hydrocarbons are formed by burial and transformation of organic matter through chemical changes that are controlled by temperature and duration. Rocks that contain sufficient organic matter for the formation of hyrocarbons are called source rocks.
    -Hydrocarbons tend to be less dense than formation waters (brines) and therefore rise upwards under bouyancy forces.
    -The upward migration is stopped if there is a permeability barrier. The hydrocarbon trap must have closure.

Key elements required for oil and gas accumulation:
    -A good source rock.
    -Sufficiently long burial of the source rock for the generation of hydrocarbons.
    -There must be a migration pathway.
    -There must be a hydrocarbon trap with a good reservoir rock (i.e., porous and permeable), a good seal (permeability barrier) and closure.
    -After accumulation of the hydrocarbons, nothing happens to degrade the reservoir.

Seismic exploration is indirect!
Source rocks, degree of source rock maturity and migration pathways are generally not detectable using seismic data. It is sometimes (but not always) possible to distinguish hydrocarbons from formation fluids. Therefore, in hydrocarbon exploration programs the ultimate goal of seismic surveys is usually to map potential reservoirs for closure. Potential hydrocarbon traps are subsequently tested by drilling.

Examples of hydrocarbon traps:
    -Termination of dipping layers at a fault
    -Termination of dipping layers at an unconformity
    -Facies change (permeable to impermeable)
    -Porous reef.
    -Bed termination at the side of a salt dome. Basic Seismic Interpretation Procedure

Common Pitfalls of Seismic Interpretation:
    -Pull-up and pull-down caused by velocity distortions.
    -Multiple reverberations

Synthetic Seismograms:
Synthetic seismograms are artificial seismic traces used to establish correlations between local stratigraphy and seismic reflections. To produce a synthetic seismogram, a sonic log is needed. Ideally, a density log should also be used, but these are not always available.


    -Convert sonic transit times to velocity by taking the reciprocal (and applying scale factor as appropriate). Initially, the logs are sampled evenly in depth (e.g., 20 cm spacing between readings).
    -Use integrated velocity to convert log depths to two-way time.
    Sometimes velocity and density logs are resampled to be spaced equally in two-way time, instead of evenly spaced in depth.
    -Calculate the reflection coefficient for each sample point. The result is a reflection coefficient (RC) time series.
    -Convolve the RC time series with an assumed source wavelet.

Often, several wavelets and wavelet polarities are tested. Positive polarity usually refers to a wavelet for which the positive central peak coincides with a positive RC. Conversely, negative polarity means that a negative trough coincides with a positive RC after construction of the synthetic seismogram.

Vertical resolution of seismic data:
Vertical resolution can be thought of as the minimum resolvable bed thickness. There are two criteria that are used to define this limit:
    -The Rayleigh limit - bed thickness (h) is 1/4 of the seismic wavelength (or, two-way time thickness is 1/2 of the dominant seismic period). This is the tuning limit - i.e., maximum constructive interference between the top and bottom of the bed takes place for this value of bed thickness.
    -Widess limit - bed thickness is 1/8 of the seismic wavelength. This is the resolution limit. For example, if the velocity is 4000 m/s and the dominant frequency is 50 Hz, then the seismic wavelength is 80 m. Hence the resolution limit is 10 m - this is the thinnest resolvable bed thickness for these parameters.

Horizontal resolution of seismic data
The horizontal resolution of unmigrated seismic data is given by the Fresnel zone, which has a width of:
    Fn = The nth Fresnel Zone radius in metres
    d1 = The distance of P from one end in metres
    d2 = The distance of P from the other end in metres
    λ = The wavelength of the transmitted signal in metres

For example, for a velocity of 4000 m/s, a two-way time of 1.0 s and a frequency of 50 Hz, we have w = 141 m!

In principle, the horizontal resolution of migrated seismic data is equal to the spatial Nyquist wavenumber (i.e., twice the CMP trace spacing - typically about 10 m). In practice, this horizontal resolution is never achieved, and a resolution of about 3-4 traces (typically 30-40 m) is more realistic.

Additional notes on salt domes:
    -Deeply buried salt is often less dense than the overlying strata, and is therefore subject to buoyancy forces.
    -Although in hand specimens halite is solid, over geologic time salt behaves like a viscous fluid.
    -Salt domes can be subdivided into swells (does not pierce overlying strata) or diapirs (overlying units are breached).
    -Stratigraphic thickening of adjacent beds can be used to deduce timing of diapirsm.

see also: 
Hydrocarbon traps
The Petroleum System

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