## 2 Data and Methods
### Data
#### 2.1.3 Data for Inversion  
This article uses partial (near and far) stacked seismic and three available well-log datasets from the studied field. Figure 3a,b consecutively show the near and far seismic section that passes through the three available wells, Well one, Well two and Well three, with Gamma Ray log from each well inserted. The acquired seismic dataset quality is considered good as the structural and stratigraphic features in this field of study can be seen clearly from the 3D seismic data. The seismic dataset over the gas reservoir demonstrates a very strong AVO anomaly (Figure 3a,b). The dominant frequency at the major reservoir zone from the full stacking volume is around 35 Hz to 40 Hz, but the seismic wavelet shows mixed phase characteristics.  
Based on the internal report, the seismic data are tied well with the log data and allow for the identification of the key seismic events. Figure 3c illustrates the seismic-to-well tie process for Well one. The seismic wavelet was extracted along the well bore by using an autocorrelation algorithm and applied with the Ricker wavelet together to produce the synthetics. The synthetics' ties to the seismic are generally good. The reliable match was obtained by manual adjustment of the synthetic to the seismic data using the check shots in Well one. The clear tie was obtained using the reflectivity series of the well and zero phase wavelet. The best synthetic tie was obtained by fixing the reflectivity series calculated from the sonic and density logs with the check shots and extracting the seismic wavelet from  
Figure 3: Seismic data input and seismic-to-well tie. Near (**a**) and Far (**b**) Seismic section of the study field showing strong AVO anomaly. Black curves are Gamma Ray logs from (left to right) Well three, Well one and Well two. The markers show thick upper reservoir, SC3, and thin lower reservoir, SC3A at each wells site. (**c**) Well one seismic to well tie. Red curve is extracted wavelet; blue is a 45 Hz Ricker wavelet (Courtesy of Petronas Carigali).  
the seismic. The extracted wavelets showed that the phase of the wavelet was near zero phases, and no lag was needed to obtain the match in wells. The synthetics were generated from full stack migration seismic volume. Most of them have a good match with calculated borehole reflectivity impedance. The synthetic seismogram yields an understanding of the influence of variant reservoir properties, such as vertical reservoir distribution, porosity, lithology and fluid saturation on the seismic wavelet.  
The three wells encountered about 20 m of total net hydrocarbon sand in the thick SC3 reservoir. The net thickness varies from 17.5 m to about 24.5 m, with porosity ranging from 24% to 30%. The net thickness of thin SC3A sand ranges from 4 m to 12 m, with porosity in the range of 18 to 23%. Porosities are mainly intergranular in nature. The SC3A sandstone reservoir is thin, with only 4.0 m of the total thickness.  
Three petrophysical logs (porosity, water saturation and volume of shale) from three available wells (Figure 4) are involved in the inversion. Porosity, water saturation and volume of shale from Well one are used for calibration, whereas the rest (from Well two and Well -three) are used for a blind test.