Need a Faster Measure of Relative Permeability? Take a CT Scan and Follow With Digital Rock Analysis

Abstract

BP is working to push digital rock testing into the mainstream of conventional development. The latest step in its decade-long journey was a deal with Exa, a software firm that partnered with BP to develop a program modeling two-phase flow in conventional reservoirs based on data from virtual 3D images of small samples of reservoir rock. Compared with methods used by traditional core labs, this approach significantly reduces the time and cost required, and offers the processing software in a form that could help broaden the use of this disruptive technology. These tools and methods will be used by BP’s technology center to generate reservoir rock property data that will be used by BP’s asset managers to consider how to better manage a wide range of conventional reservoirs, said Joanne Fredrich, upstream technology senior advisor at BP. The system measures relative permeability—in this case the degree that flow rates are reduced when oil and water are mixed—using a 3D digital image based on scans of small rock samples by a micro CT, known in the medical field as computed tomography. CT machines are used for medical scanning and are able to image extremely fine details. Relative permeability has been notably lacking from BP’s long list of conventional reservoir tests using digital rock analysis, which range from measures of reservoir porosity to electrical resistance. Absolute permeability has been available, but that measure of single-phase flow is not a good representation of reservoir reality. “We have so little relative permeability data. We see this as a potential game changer for subsurface modeling that more accurately characterizes reservoirs,” Fredrich said. Measures of relative permeability have long been done in core labs. Digital analysis can reduce the time required to get back relative permeability results from a year or more to a couple of weeks or less, and the software can be scaled up to allow BP to speed work by running simulations on thousands of processors at its supercomputing center, she said. The software deal with Exa allows BP to use the software it helped develop with the maker of fluid flow simulations, and for Exa to market it to other users. “We are the first company to bring an accepted, credible technology to market” to simulate multiphase flow and predict relative permeability using this sort of data, said David Freed, vice president of oil and gas for Exa.