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Thursday, January 28, 2016
Reduce Cost for Petroleum Exploration with Training on your project Service (15$ per hour)
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Monday, January 18, 2016
Monday, January 4, 2016
advantages of borehole seismic (VSP)
advantages of borehole seismic (VSP)
Borehole Seismic definition
- The name given to seismic surveys, where the seismic sensors are normally lowered into the well bore. The seismic sensors may be single component, 3 component, and could be deployed at single levels, or several levels in the well bore
Why borehole seismic?
- · The comparison between a seismic section (in two-way time) and an acoustic log (interval transit time versus depth ) leads to questions about the relations between the two types of data and the possible combination of their corresponding datasets
- · The acoustic log provides an obvious link between geophysics, seismic and well logging data. Although covering different frequency bands (acoustic logs: in the order of 10 kHz; seismic: ranging from about 10 to I 00 Hz), the two techniques are based on the same Jaws of wave propagation but with different mythologies. Under a certain number of conditions, the seismic measurements collected at these different frequencies can be compared and used to improve knowledge of reservoir characteristics. Acoustic log has a very different vertical and lateral range of investigation compared with seismic surveys (surface or borehole)
the depth-to-time conversion of well log data is carried out using the acoustic velocities of
formations obtained from acoustic logs (sonic logs), this
method is insufficient
to provide an effective
comparison between seismic and logging survey
datasets. There are
discrepancies between the acoustic velocities derived from logging and seismic
surveys, it is thus necessary to perform a sonic calibration for the depth-time
conversion .
- · The sonic log calibration involves establishing a time-depth relation consistent with the seismic survey yielding the same vertical resolution provided by the sonic log. In other words, the sonic log measurements are recalculated to be compatible with variations in fluid and lithological composition, so the integrated travel time between two depth readings can be matched with the corresponding data from well velocity surveys.
- A well velocity (or check shot) survey is carried out by measuring the travel times of head waves emitted from a surface shot by means of a geophone or an hydrophone placed at various depths in a well. Check shot surveys are the predecessor of vertical seismic profiles. Vertical seismic profiles (VSP) may use more sophisticated tools to record the entire seismic wave train generated by surface source and transmitted through the earth filter downward. A VSP survey is usually recorded at a much higher density of depth points but may not cover the entire wellbore.
- Once the calibration has been carried out and a corrected time-depth relation established, it is possible to compare the well (logs) with surface seismic data. One technique employed for this purpose is the creation of a synthetic seismogram using density and acoustic velocity logs. Bulk density and acoustic velocity logs are used to create an acoustic impedance log. After depth-time conversion, the reflection coefficients derived from the acoustic impedance log are then convolved with an appropriate wavelet to produce the synthetic seismic section (often referred to as a seismogram).
- Seismic data obtained from the vertical seismic profile (VSP) with or without source offset, are processed to provide seismograms at seismic frequencies that are directly comparable with synthetic sections and surface seismic sections. Even though these data have a poorer vertical resolution compared with well logging and a restricted frequency range, they can be used to adjust profiles obtained from seismic reflection surveys carried out at the surface. In addition, borehole seismic surveys can be used for defining appropriate operators for stratigraphic deconvolution and converting seismic sections to acoustic impedance sections or logs.
☯ Where is my reservoir top on my seismic
section?
☯ Are there faults near my borehole?
☯ How far my reservoir laterally extends?
☯ Where is my desired formation top in the well
below TD?
☯ Is there overpressure zone below TD?
☯ I want to make synthetic seismograms!
☯ I want to make a velocity model at the well
location!
☯ I need information to better process my
surface seismic
data!
Objectives of Well-Seismic Ties
- · The objectives for performing a well-seismic tie are listed here
- · Wells, of course, are registered in units of depth – feet or meters
- · Seismic data is recorded and usually worked with a vertical scale of 2-way travel time
- · To relate well data to seismic data, and vice versa, we have to handle this change in vertical scale units
- Well-seismic ties allow well data, measured in units of depth, to be compared to seismic data, measured in units of time
- This allows us to relate horizon tops identified in a well with specific reflections on the seismic section
- We use sonic and density well logs to generate a synthetic seismic trace The synthetic trace is compared to the real seismic data collected near the well location
- The well-seismic tie is the bridge we need to go from seismic “wiggles” to the rocks that produced the “wiggles” and our interpretation of the subsurface geology (figure 22)
- The purpose and required accuracy of a well-seismic tie varies with the stage of our studies
- If we are doing regional mapping, e.g., mapping a significant erosional unconformity or a flooding surface, then our tie does not need to be very precise, within 1 or 2 seismic cycles (peaks or troughs) – and the seismic data quality does not have to be very good In the exploration stage, we would like to tie well data, e.g., the top of a stratigraphic horizon/marker within ½ a cycl This requires good seismic data quality
- In the exploitation stage (development & production), we need to not only know the seismic event within ½ a cycle, but the shape of the real and modeled seismic trace should be quite similar
- For this, we need very good seismic data quality
- If we obtain a good character (shape) tie between the real and synthetic traces, then:
- We would then be able to extract various seismic attributes (measures of the seismic wavelets) to predict rock and fluid properties We may also be able to use a process called inversion to transform the seismic data into an estimate of the rock properties in cross-section views or as a 3D volume (if we have 3D seismic data)
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