--> Abstract: Quantitative Estimation of Oil-Water Contact in a Jurassic Clastic Reservoir using Elastic Wave Propagation, by Zhang, Zhao; Sun, Yuefeng; #90163 (2013)

Datapages, Inc.Print this page

Quantitative Estimation of Oil-Water Contact in a Jurassic Clastic Reservoir using Elastic Wave Propagation

Zhang, Zhao; Sun, Yuefeng

Over 50% of the proven hydrocarbon reserves of the UKCS Northern and Central North Sea occur within Jurassic. Field and laboratory data have indicated that low frequency anomalies are related to hydrocarbon occurrence in these areas. However, these anomalies could also be attributed to changes in lithology and water saturation, which makes practical application of the anomalies in mapping fluid contact difficult. Experience shows that this technique does not always effectively determine fluid contacts. It is difficult to reduce the uncertainties due to lithology changes and water-saturated zones. We attempt using a recently developed spectrum gradient analysis method via variable-factor S transform to identify oil-water contact basing upon elastic wave propagation in fluid-saturated porous media.

In the simplified poroelastic model, the rock reflection coefficient consists of two parts: (1) rock skeleton reflection coefficient, which is not dependent on frequency; and (2) the frequency-dependent part, which depends on fluid viscosity and permeability. Aiming to reduce the impact of rock matrix, frequency gradient analysis defines the relation between the amplitude spectrum gradient attribute and fluid properties. Variable-factor S transform allows the dynamic analysis of spectrum over time and provides additional parameters to control the time and frequency resolution. Spectrum gradient analysis using variable-factor S transform thus reduce the influence of lithology changes and allows a continuous time-varying analysis of fluid changes on differential frequency content. Our result shows that, in the target reservoir, all wells producing water (low viscosity fluid) show low amplitude and the wells with the high oil (high viscosity fluid) production rate are found close to the zones of high amplitude. Tracking the amplitude anomalous in 3-D domain can give the initial interpretation of an oil saturated sand zone which matches the existing geological model. These findings enable us to improve rock-physics-based quantitative seismic interpretation techniques and accurately identify commercially viable targets before drilling.


AAPG Search and Discovery Article #90163©2013AAPG 2013 Annual Convention and Exhibition, Pittsburgh, Pennsylvania, May 19-22, 2013