Reservoir And Elastic Property Prediction Away From Well Control
Authors: Spikes Kyle T. , Dvorkin Jack P. 
Published: October 2008

The ultimate goal of this effort is to quantify lithology, fluid, and porosity from seismic data. We approach this goal by generating synthetic seismograms and comparing them to real seismograms, with the expectation that a similarity in the seismic response indicates a similarity in the underlying rock properties, specifically, lithology, fluid, and porosity (LFP). The synthetic seismic approach also can be used to understand the sensitivity of real data to LFP. The starting point for synthetic seismic generation is rock physics analysis and geologic interpretation of well data. Then a geological model of the subsurface with geobodies and expected depositional and diagenetic patterns outlined. Next, geobodies are populated with clay content and the corresponding porosity and hydrocarbon saturation at the well log scale. These rock properties are translated into the P- and S-wave velocity and bulk density by using a rock physics model. Then synthetic seismograms are produced from the elastic properties. We illustrate this methodology using well data from a fluvial environment in which the clay content is related directly to the total porosity by the dispersed clay model and to oil content via irreducible water saturation. These properties are related to the velocity and density by the Raymer-Greenberg-Castagna model, which is appropriate for mature sand/shale sequences. We use standard schemes of depositional models to construct a vertical geological section of grain size distributions, with a fluvial channel that includes the well. We examine two - the massive and gradational - depositional sequences within the channel. In the case under examination, synthetic seismic appears to be sensitive to lithology, fluid, and porosity. This result indicates that LFP information can be extracted from real seismic.

Introduction

The depositional environment, diagenesis, burial, and compaction can vary substantially within the same basin or within the same stratigraphic facies. These factors may directly affect lithology, fluid, and porosity (LFP). LFP, in turn, affects the elastic properties of the rock and, subsequently, the seismic response. The main question of exploration is how to translate seismic data into LFP. Our approach to this problem is synthetic seismogram generation and comparison thereof to real seismic data. If the real and synthetic data are similar, we assume a similarity in the underlying LFP. Of course, this approach carries nonuniqueness because multiple combinations of reservoir properties and geometries can produce the same seismic signature. However, the power of the synthetic seismic approach is that responses can be generated easily, rapidly, and massively for various scenarios of lithology, porosity, and fluid distributions in the subsurface. By so doing, the geophysicist can create a site-specific catalogue of seismic signatures to assess various possibilities and probabilities contained in the field data. Also, synthetic seismic data helps to understand the sensitivity of real data to LFP.

Well data represent the rock properties along a one dimensional spatial trajectory. Therefore, information contained in the well data lacks lateral continuity and cannot be used alone for reliable predictions of rock properties where lateral geologic variation is significant.