Oil and gas producers who ply their trade in shale reservoirs have benefited in ways not likely even imagined in years past.
Given shale’s role in elevating the United States to a world leader in oil production, it would appear that any technical obstacles to producing from this challenging rock have now been conquered.
Not so.
Granted, hydraulic fracturing technology — which continues to evolve — and other innovations have made all the difference in getting the hydrocarbons to move from this type of reservoir rock into the lateral legs drilled out from the vertical wellbore.
Still, much remains to be learned about these nanoporous shale deposits.
Given the super small silt- and clay-size grains of which shale is comprised, the intervening tiny pores are isolated from one another for the most part. This prevents fluid flow like that with, say, a coarse-grain sandstone having larger, interconnected pores.
Without connectivity, the needed permeability that enables natural flow is absent. The larger, interconnected pores associated with coarse grains, however, ordinarily allow the contained fluids to flow to the well, sometimes encouraged by injected water.
Today, the now-commonplace hydraulically-induced fractures can essentially “connect” the minuscule pores in shale. On the downside, this fails to provide the producers with any understanding of pore distribution and the structure of the shale zone(s) overall, which is crucial to achieve the most effective, efficient production.
The Coarse-Grain Approach
The Energy and Environmental Science & Technology Directorate (EES&T) at the Idaho National Laboratory (INL) in Idaho Falls has scientists working diligently to better understand how fluids might flow through the small pores in shales where the silt- and clay-size particles can measure as small as less than 0.004 millimeters.
INL EES&T computational scientist Yidong Xia commented that new computer simulations can more effectively analyze the underlying physics involved and possibly lead to more efficient oil and gas extraction.
These simulations are less power-hungry than other methods and incorporate high-resolution shale sample imagery, according to Xia.
Using what’s dubbed a coarse-grain approach, he and fellow researchers have modeled the nanoscale-pore fluid as a collection of particles where each particle represents a cluster of only a few molecules. The scientists then noted an exceptional decline in computational power required to run the simulation.
The model used is a many-body dissipative particle dynamics model (MDPD), which can simultaneously capture both the discrete features of fluid molecules in nanometer size pores and the continuum fluid dynamics in larger pores. Plus, it’s relatively easy to parameterize, according to Xia and his colleagues.
These features combined make it especially suited for simulating complex fluid flow in multi-length-scale nanopore networks in shale.
The INL team emphasized that a significant feature of this application is the integration of a high resolution FIB-SEM (focused ion beam scanning electron microscopy) digital imaging technique to the MDPD model for providing 3-D voxel data. These data harbor the critical geometrical and compositional info of shale samples.
Simulations thus far have included a forced two-fluid flow in a late Devonian/early Mississippian-age Woodford shale sample measuring a few millimeters in diameter.
Researchers at the University of Utah oversaw this effort, where the ion beam cut through the sample, yielding slices that were scanned to provide a 3-D image of the rock along with its pore structure at the scale of a nanometer. Xia noted that the images were incorporated into the computer model to simulate fluid flow throughout the scanned nanostructures.
“Results (from this and other simulations) indicate this model can be used to deliver reasonable simulations for multi-component, multi-phase fluid flows in arbitrarily complex pore networks in shales,” Xia and fellow scientists noted in a paper published in the journal “Physics of Fluids.”
Wider Application
One sample, however, is just that.
He remarked that simulations using multiple samples throughout the Woodford likely could serve to provide much more than just a cursory glance into the basic physics of its makeup.
The future for this technology is not yet being widely discussed in the public domain.
“We’re looking at a very small region of the shale in our (published) articles, but it may not be enough to understand the whole picture,” Xia said. “In order to go further, we may need to do a lot more work.
“Shale is very heterogeneous, and our technology is aimed at a much larger scale than has been described,” he emphasized. “We want to give a better picture of the (fluid) flow through the shale.”
For now, mum’s the word, given that research proposals are going out “as we speak,” and these type endeavors are always competitive.
Xia emphasized they’re not in the business of endorsing technologies or energy sources.
It’s all about the science.
“Our focus is to better understand the basic physics of shale,” he noted.