Since the “shale gale” kicked off several years ago, it has been characterized by the kind of land-grab frenzy not seen in North America in many years. Desperate to use existing rigs and maintain their acreage positions, operators obeyed the “drill, baby, drill” mantra and drilled countless vertical and horizontal wells.

Not all of them were successful.

Now that operators are getting more familiar with their shale plays, they’re starting to take a more studied approach that involves geophysics, geology, rock physics, and petrophysics to really plumb the depths of these inscrutable shales. In a workshop at Hart Energy’s DUO conference in Denver on using exploration technology for shale development, three panelists talked about tools that help oil companies get more information to better exploit their fields.

Chris Neale, vice president of MicroSeismic Inc., argued for the use of microseismic information not only for frac monitoring but for field monitoring as well. His company has pioneered the use of permanently buried arrays to periodically monitor fields.

“You can monitor every well,” he said. “It’s the best tool for looking at important changes over the area.”

Microseismic monitoring helps determine the direction of maximum horizontal stress since fractures propagate in that direction. Understanding existing fractures and faults aids companies as they drill and frac additional wells.

Neale said his company is attempting to develop a tool that will calculate EUR from microseismic data. To do this the company maps out a discrete fracture network and plots the magnitude of the microseismic events against their frequency. The magnitude can be related to the injected fluid volume. He added that data source attributes are critical factors in this calculation.

In one example, Whiting Petroleum monitored 150 wells and gathered a database to analyze and plan its operations, including refrac candidates, waterflooding possibilities, and CO2 injection.

“Microseismic evaluation provides critical data for statistical evaluation,” Neale said.

Dr. Lee Bell, chief geophysicist for Geokinetics, suggested an additional tool for the toolbox – multicomponent data. Measuring shear as well as compressional waves provides a control on the rigidity of the formation, Bell said.

Shear waves often split when they encounter fractures, with the faster waves traveling parallel to the fractures and the slower waves traveling perpendicular. The difference between the fast and slow waves provides a measurement for anisotropy, a determination of fracture density. The shear wave splitting also can be used to determine fracture orientation.

In a Marcellus shale example, Bell showed that the multicomponent seismic showed better horizontal anisotropy with better signal-to-noise than a similar survey in which amplitude vs. offset analysis was used on compressional waves to estimate the shear waves.

Overall, he said, the best surveys require wide-azimuth acquisition design, homogeneous offset and distribution, and multicomponent seismic.

Echoing the theme of long offsets, John Maher, Denver Center manager for Global Geophysical, showed a case study over the Silo field where far offsets were measured in both the inline and crossline directions. Traditional surveys, he said, only measure the far offsets in one direction. But the 360-degree azimuth and offset helps to fill in missing data.

When Global processors used refraction statics to correct for the shallow signals, a sinusoidal pattern emerged, indicative of azimuthal anisotropy. This suggested a strong correlation between the fast direction of the delay time anisotropy, which correlates to the topography of the area, he said.

The refraction statics could not have been resolved without azimuthal delay time anisotropy, he said, and having the far offsets proved to be the most important element in this resolution.

He added that tomographic fracturing is an emerging technology that will lead to cost reduction, fewer wells, fewer frac stages, and enhanced recovery.

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