Abstract
A rock physics based seismic interpretation workflow has been developed to extract volumetric rock properties from seismically derived P- and S-wave impedances, Ip and Is. This workflow was first tested on a classic rock physics velocity-porosity model. Next, it was applied to two case studies: a carbonate and a clastic oil field. In each case study, we established rock physics models that accurately relate elastic properties to the rock’s volumetric properties, mainly the total porosity, clay content, and pore fluid. To resolve all three volumetric properties from only two inputs, Ip and Is, a site-specific geology driven relation between the pore fluid and porosity was derived as a hydrocarbon identifier. In order to apply this method at the seismic spatial scale, we created a coarse-scale elastic and volumetric variables by using mathematical upscaling at the wells. By using Ip and Is thus upscaled, we arrived at the accurate interpretation of the upscaled porosity, mineralogy, and water saturation both at the wells and in a simulated vertical impedance section generated by interpolation between the wells.
Highlights
Most rock physics models are designed to arrive at the elastic properties of porous rocks from their petrophysical properties, such as the total porosity, mineralogy, organic matter content in unconventional reservoirs, and pore fluid saturation and individual fluid phase properties
The seemingly unresolvable issue of such interpretation is the so-called “rock physics bottleneck,” meaning that the few elastic properties depend on a larger number of volumetric and environmental inputs, such as porosity, mineralogy, water saturation, differential stress, and rock-frame texture
We investigate the applicability of our rock physics based seismic interpretation workflow to quantifying porosity and pore fluid from measured elastic properties
Summary
Most rock physics models are designed to arrive at the elastic properties of porous rocks from their petrophysical properties, such as the total porosity, mineralogy, organic matter content in unconventional reservoirs, and pore fluid saturation and individual fluid phase properties Such current models are based on various effective medium theories taking into account the pore-space geometry, degree of cementation, as well as such conditions as the differential pressure and water saturation. These models (or transforms) usually predict the elastic P- and S-wave impedances (Ip and Is, respectively), as well as the bulk density (ρb), from the aforementioned petrophysical and environmental inputs. Dvorkin and Alkhater (2004) found, by plotting Ip vs. porosity (φ) from wireline data in an unconsolidated-sand offshore reservoir, that two very distinct Ip–φ trends emerge, one for the gas and the other for the liquid (oil and water)
Sign-in/Register to view highlights & summary Sign-in/Register to access full text options 
Free) 
Talk to us
Join us for a 30 min session where you can share your feedback and ask us any queries you have
Schedule a call
