--> --> Seismic Rock-Property Transforms for Estimating Lithology and Pore-Fluid Content, by Haitao Ren, Fred J. Hilterman, Zhengyun Zhou, and Mritunjay Kumar; #90052 (2006)

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Seismic Rock-Property Transforms for Estimating Lithology and Pore-Fluid Content

Haitao Ren1, Fred J. Hilterman1, Zhengyun Zhou1, and Mritunjay Kumar2
1 Center for Applied Geoscience Excellence, University of Houston, Houston, TX
2 Geosciences Department, University of Houston, Houston, TX

Using well-log curves from the Gulf of Mexico shelf and deep-water environments, velocity and density values from approximately 500 sand reservoirs and their encasing shale intervals were cataloged. These unconsolidated sand reservoirs are located at depths between 1600m and 6500m and are predominantly Pliocene to mid-Miocene in age. Over half of the reservoirs contained hydrocarbons. Fluid substitution was conducted so that all 500 reservoirs have velocity and density values (or estimates) for gas, oil and brine saturation. While conventional depth plots for velocity and density trends were very unstable and showed no apparent correlation, two robust reflection-coefficient transforms emerged. The first transform relates the normal-incident reflection coefficient (NI) for either gas or oil saturation to the NI of the equivalent brine-saturated reservoir. We called these pore-fluid transforms. The second type of transform relates the near-angle reflection amplitude to the far-angle reflection amplitude for various pore-fluid saturations. Surprisingly, the change in amplitude from near to far offsets is predominantly dependent on lithology (shale content, porosity, etc) and not the pore-fluid saturant. Thus, this type is named the lithology transform. Using the lithology transform along with near- and far-angle seismic amplitude maps, reflection coefficient maps for various pore fluids are generated. Of significance is that the seismic maps now represent reflection coefficients. Next the reflection coefficient map for the down-dip brine-saturated portion of the prospect is changed to represent various hydrocarbon saturations using the pore-fluid transforms derived from the catalog. When the converted amplitude of the down-dip portion of the prospect matches the prospect amplitude, then an estimate of the pore fluid and water saturation are known.