Fluid Discrimination Applying AVA Potentiality for Carbonate Reservoir in UAE
Authors: Mahmoud Sabry Lotfy , Othman Adel , Soroka William L. , Al Jeelani Abubaker Habib , Kamel Diaa Al Deen 
Published: May 2016

Well based modeling and seismic data analysis were used to investigate the potential of Amplitude Variation with Angle (AVA) for fluid discrimination in a high porosity carbonate reservoir in a producing UAE oil field. Gassmann fluid substitution was used to model well log data, which included compressional and shear sonic logs and density logs to produce synthetic well logs representing the reservoir at 100% fluid saturations of brine, oil and gas at reservoir pressure and temperature conditions. The average VP/VS ratio for brine saturated reservoir (~2.0) was observed to be higher than both the oil (~1.7) and gas (~1.6) saturated reservoir cases.

The modeled brine, oil and gas logs were used to calculate the AVA responses at the top and base of a thick, 25–35 % porosity reservoir layer using the Zoeppritz equations. The responses for all three fluids were found to be a Class-IV type AVO anomaly. Seismic amplitude variation on the synthetic CDP gathers was successful at discriminating brine from hydrocarbon but could not differentiate oil from gas. These encouraging results on synthetic data suggest that with good quality seismic data it can be possible to see a difference in AVA responses between brine and hydrocarbon filled porous reservoirs. An AVA study was performed using available relative amplitude CDP gathers along a 2D seismic line extracted from a 3D seismic volume. The results were able to discriminate between areas saturated with brine from those with hydrocarbon. The real seismic results were in good agreement with synthetic model results. The angle stack analysis was successful at improving the signal-to-noise ratio in lower fold seismic data and reduced the input data size requirement when dealing with larger CMP gathers. The effects of varying key reservoir and seismic properties on AVA response were examined to help understand the potential for misinterpretation.

Introduction

Seismic amplitude responses are affected by the types of rock present, the degree of consolidation, the saturating fluids plus rock properties such as porosity of the reservoir and the encasing layers. Gassmann fluid substitution is used to produce log data, which are representative of porous carbonate reservoirs filled with 100% brine, oil and gas. The fluid properties represent typical reservoir fluids under typical reservoir pressure and temperature conditions. The average VP/V S ratio for a brine saturated reservoir is approximately 2.0, for an oil saturated reservoir around 1.7 and for the gas saturated case around 1.6. Synthetic CMP gathers were created from the brine, oil and gas log data. The synthetic CMP gathers were put through an amplitude analysis at the top and base interfaces of the reservoir layer and found to be AVO class-IV anomaly and were successful at discriminating brine from hydrocarbon but could not differentiate oil from gas. These encouraging results on synthetic data suggest that with good quality seismic data, it should be possible to see a difference in AVA response between brine and hydrocarbon filled porous reservoir. Modeling from the available well log data is used to calibrate the observed seismic AVA responses. AVA analysis was performed on real seismic along a 2D seismic line extracted from a 3D seismic volume over a carbonate reservoir in U.A.E. This case history over a known hydrocarbon occurance was used to confirm that different fluid types can be detect ed and agreed with the modeled results. The AVA responses were validated using the reservoir saturation information from the reservoir model and simulation modeling.