LECTURE 18&19

SEISMIC REFLECTION SURVEY
1. minimises subsurface mapping risk away from hard data locations (wells)
2. acoustic imaging of the subsurface in 2way time
3. Acoustic pulse is partially transmitted+ reflected at boundaries betw. rocks with different acoustic impedence
4. complicated extension of echo (water depth) sounder
  1. source emit sound down through earth- interfaces where impedance changes partially reflect sound up-record- reflection strength determined by difference acoustic impedence (Z) across interface.
  2. reflection coefficient determine amplitude of reflected wave
  3. move device in a line produce 2D mapping, in a grid produce 3D mapping. difficult to move device-3D is provide by many closely-space receivers in grid.
5. Depth resolution
  1. poor relative to log+other well data (spatial/geographic resolution). typical range: quarter to half wavelenth
  2. size of smallest distinguishable features in the data
6. Steps
  1. 1. Acquisition
    1. survey is designed+shot
    2. compositions
      1. source of sound
        air guns (marine)
        vibroseis truck (land)
        frequency range: 8-80Hz
      2. receiver detect returning echo
        geophones (land)
        hydrophones (marine)
      3. amplify, digitise, record data instruments
    3. Cheaper in sea (equipment loaded on boat, operate day+night) than land (manual load equipments, electric cables)
  2. 2. Processing
    1. intensive computer processing-image from seismic data
    2. data pass through separate processes, different purposes
      1. Random noise suppression
        improve signal:sound
        Common Midpoint Shooting (CMP)
        data shot so many reflections record from same point-reflections add together- make stack section- better signal-noise ratio than original data
        CMP gathers: raw, recorded shot records. not easy integret
        combine CMPs -transform to geologically meaningful display that can be integret
        Velocity Analysis for correcting Normal Moveout (NMO)
        Stacking (summing) NMO-corrected CMP gathers - attenuate noise- improve S:N ratio
        Range of possible S:N improvement
      2. Coherent noice (multiples)
      3. Resolution enhancement
        better resolution -more detail image
      4. Migration of received acoustic energy to correct reflector location
        migration moves reflection to accurate location
        when beds are not horizontal-reflections different from vertical receiver-distorted view of structure on seismic section
        distortion increase with deep, dip, velocity
  3. 3. Intepretation
    1. image is interpreted from seismic data- maps, geological models of subsurface
    2. to define explotation + development well locations
    3. Good integretation: internally consistent with available well data+ basic geological concepts
    4. Basic procedures
      1. picks significant events+ faults in each seismic section
        time+ amplitude of each event is recorded
      2. mapping stratigraphic features
        predict environments of deposition +rock types from reflection pattern
      3. mapping reservoir properties
        porosity map (well data)
        seismic event amplitude at reservoir level correlation with porosity
        transform seismic amplitude - more detailed porosity map
      4. mapping pore fluids
      5. dept conversion
        calculate depth from seismic times. requires velocity from well/seismic data
    5. Key intepretable features
      1. seismic profile section
        seismic horizons (coherent reflection events)
        faults (displaced coherent events
        3D better than 2D
        provide a volume of data
        view in any orientation
        able to see channels from origin

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