Comparison of Probabilistic Techniques in the Study of Fluid Effects on Seismic Properties
Authors: Ampomah W. , Chen H. Y. , Assad J. 
Published: May 2016

Abstract
The parametric method is known for probabilistic estimation of hydrocarbon reserves (Smith et al. 1993). This analytical approach is not "black boxy" as compared to the Monte Carlo simulation. It uses common statistical information. More so, the relative impact of the input parameters is easily ranked to ascertain each individual's contribution to the total uncertainty.
This paper elaborates the use of the parametric approach to analyze the uncertainty associated with the effect of reservoir fluids on seismic properties. The outcome is compared with Monte Carlo simulation and deterministic techniques. A forward modeling algorithm based on fluid substitution procedure is employed in the study. The model assumes each reservoir fluid such as black oil, volatile oil, gas condensate, dry gas and water is saturated in the rock pores. The effect of these fluids on seismic properties such as compressional velocity, shear velocity, acoustic impedances is simulated with uncertainty. Moreover, saturation changes effect on these seismic properties in a two phase system is also studied. Beyond these, a relative impact analysis is carried out to know the individual input data's contribution to the total uncertainty. Sandstone reservoir rock and fluid properties from laboratory are used for the analysis. Scale-up techniques are used to ensure consistency between laboratory and seismic scale data.
The results from both parametric and Monte Carlo simulation showed a good agreement. The results showed a unique effect exhibited by each reservoir fluid on the seismic properties. This approach can assist in identifying reservoir fluids especially at in-situ conditions from the seismic results. The outcome also showed a similar observed result in the Wyllie plot of velocity versus fluid saturation changes. The prediction of saturation effect on seismic properties would enrich time-lapse reservoir monitoring in identifying unswept zones and aid in optimizing in-fill drilling.

Introduction
Seismic data analysis is one of the key techniques recently used for characterizing reservoirs and monitoring subsurface pore fluids. Even though there have been considerable advances in 3D seismic data processing, the interpretations of the seismic data for rock properties still pose many challenges.
Rock physics is an important aspect connecting seismic response to the presence of in-situ reservoir fluids and to reservoir characterization. Modeling the effects of fluids on rock velocity and density is a basic method used to unravel the influence of pore fluids on seismic data. Gassmann (1951) equation is the predominant used relations to model seismic velocity changes due to different fluid saturations in the reservoir. This phenomenon is viable in the analysis of direct hydrocarbon indicators (DHI). These include: bright spot, amplitude variation offset (AVO) and last but not the least time lapse reservoir monitoring. The division of reservoir fluids between the liquid and vapor phases depends mainly on the temperature and pressure. The state or phase of a fluid in the reservoir usually changes with pressure in an isothermal process (Craft and Hawkins, 1959). There are five (5) categorizes of reservoir fluids (McCain, 1990). They are: black oil, volatile oil, retrograde gas, wet gas and dry gas.
Also, hydrocarbon production directly affects the reservoir properties (saturation gas, oil and water, pressure and temperature). In order for time lapse monitoring to be effective, the change in reservoir properties must cause a detectable change in the seismic parameters.