Print this pageAAPG GEO 2010 Middle East
Geoscience Conference & Exhibition
Innovative Geoscience Solutions – Meeting Hydrocarbon Demand in Changing Times
March 7-10, 2010 – Manama, Bahrain
Shaybah 3D Amplitude Inversion with Interbed Multiple Modeling
(1) ETSD, Saudi Aramco, Dhahran, Saudi Arabia.
(2) RCD, Saudi Aramco, Dhahran, Saudi Arabia.
(3) EOD, Saudi Aramco, Dhahran, Saudi Arabia.
Amplitude inversion has been used routinely throughout the industry to help assess the reservoir quality and derive reservoir properties such as porosity. In cases where interbed multiple contaminations interfere with the primary reflectivity, the inversion results are questionable unless interbed multiples can be simulated in the inversion procedure.
In this paper, we demonstrate the use of zero-offset modeling, to simulate interbed multiples, observed in a 3D seismic dataset, acquired over the Shaybah oil field. We identified the interval from which interbed multiples were generated and produced a reasonable 3D impedance model for use in the field’s development drilling program.
A “layer-stripping” type modeling approach was used to identify the interval from which the interbed multiples were generated. Three key geologic intervals between the surface and the base of the reservoir were identified as candidates for the starting layer from which the interbed multiples were modeled. To begin, the shallowest formation of the three was designated as the starting layer. Synthetic traces with primary and interbed multiple reflections were generated and compared with the measured seismic data. This procedure was repeated for the deeper two consecutive formations. At the conclusion of this modeling exercise, it was determined that using the shallowest formation as the starting layer produced the best match between the synthetic and measured seismic data.
The inversion algorithm used a model-based method where the starting model was generated by interpolating known log impedances between existing well control based on the interpreted seismic time horizons. The initial model was then optimized by iteratively updating the impedance to minimize the error between the synthetic, generated from the model, and the seismic. The final inversion results were evaluated by matching the measured 3D seismic data to the impedance logs at the wells. Comparison of seismic and inverted impedance volumes showed that the top of the reservoir was more clearly defined by the impedance volume; whereas the 3D seismic signature for the top of the reservoir is poorly defined due to the presence of the multiple interference.