Modeling can be viewed as a spectrum of activities—from the speculative nature pre-discovery model of what may or may not prove to be a reservoir, to the near physical reality of a refinery simulator. What separates the speculative from the ‘real’ is the ease with which the model can be checked with additional measurement. Ultimately, models can become so well-constrained that they can be used to perform ‘experiments’ themselves—such as automobile crash testing.
In a recent presentation* to the Canadian Well Logging Society, Ingrain advisor Jack Dvorkin made an elegant case for a step change in reservoir analysis, with computer tomographic (CT) scanning providing the constraints to high fidelity computer models of reservoir rocks. Dvorkin, whose other life is as a researcher in the geophysics department of Stanford university, describes the approach as ‘quantitative virtuality,’ a new way of relating measurements such as well logs or seismics, to physical reality.
Stanford studies on the North Sea Troll gas supergiant have shown some counterintuitive results that were resolved by computer modeling. Compression and shear wave velocity ratios varied widely for similar porosity ranges—depending grain cementation. This was ‘understood’ by computer modeling of the whole process, from an unconsolidated sand through digenesis and burial.
Permeability, an elusive parameter for conventional approaches, is usually categorized by expensive special core analysis in the lab. With quantitative virtuality, full forward modeling of the rock’s history has been used to relate permeability to grain size, pore topology and membranes. As Dvorkin says, ‘experiment, experiment, experiment...’
Ingrain’s 3-D NanoXCT** imaging system gives a ‘true’ 3D representation of the rock. Images of Saudi Arabian carbonates even show fossils in detail. Armed with such high resolution images, Ingrain’s scientists run fluid flow ‘experiments’ on the computer. Checks with lab measurements sometimes produce widely different results. In one case, a difference in permeability of two orders of magnitude was observed. It turned out that the computer was right and the lab was wrong! Multiphase flow is very hard to implement in lab experiments—and these can be performed more accurately, cheaper and faster in the computer where heterogeneities can be correctly categorized. Ultimately, Dvorkin sees modeling of rock physics right down to the quantum scale.
The computer can also be used to ‘decrack’ cuttings for numerical experiments or perform virtual experiments on different fluid fill—which would take weeks in the lab. Massive databases of rock properties can now be delivered in near real time.
© Oil IT Journal - all rights reserved.