It seems that more and more I’m writing about new developments in processing and software that have only been possible in recent years because of better computing power. Whether it’s new algorithms to process seismic data or faster reservoir simulation runs, computer-savvy folks seem to be like kids in a toy store with all of the new compute power at their disposal.
The e-Core technology simulates natural processes of sedimentary rock formation such as sedimentation, compaction and diagenesis. The input data to the rock modeling is high-resolution thin section images, and the 3-D numerical rock models (shown) are used for the calculation of petrophysical properties. (Image courtesy of Numerical Rocks) |
I talked to Ivar Erdal, chief executive officer, about the company. Erdal joined Numerical Rocks in 2005 after working at a core analysis lab in Trondheim, Norway.
He described Numerical Rocks’ technology as a predictive method that takes a small rock sample and builds rock models.
“We do need a small piece of rock, and that’s very important — we’re not making this up out of our heads,” Erdal said. “It’s based on pure physics and geological understanding of the material.” The rock models predict not only porosity and permeability but also simulate the two-phase fluid flow properties of the reservoir.
Numerical Rocks offers both software, a product called e-Core, and services, which include preparation of the rock sample, reconstruction and verification of 3-D rock models, calculation of petrophysical parameters, extraction of numerical pore networks, two-phase flow studies, and sensitivity studies on wettability and other parameters.
Currently the technology is being used on cores because the goal has been to produce the same kinds of data that would be gathered in a core laboratory. But exciting developments are underway for the future. Erdal said that if the process can be used on drill cuttings, it could provide a very early look at the reservoir parameters that would be available months before detailed core analysis results.
“If we can get the drill cuttings, we can do the same modeling as we do on the piece of core plug,” he said. “That will be interesting because you’re then able to not only predict porosity and permeability but also do the fluid flow simulation just from a small piece of the drill cutting.”
The main obstacles to this approach are logistical — it would require the sample preparation to take place at the rig site to develop a digital representation of that drill cutting, which would then be sent to the Numerical Rocks processing center which is currently in Trondheim. But Erdal said that it is already possible to do this with relatively inexpensive equipment.
Once the digital representation reaches Numerical Rocks, it would then take 3 to 5 days to run the simulation, he added.
Today most of Numerical Rocks’ clients are more interested in the service aspect than the software, and Erdal said there will be a learning curve before companies feel comfortable simply purchasing the software and running their own simulations. “But I think eventually they will ask to have the software tools in-house as well,” he said. “That’s our ultimate goal, actually.”
His ultimate goal is not to be a replacement for detailed core analysis but rather to give companies more data than they’re used to having to populate their models and get those data to them in a streamlined fashion. “I believe this technology will become a standard tool for the oil companies to describe their reservoirs in the future,” he said.
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