The Eagle Ford shale play in South Texas has plenty to offer. But operators will have to come to grips with its complexities.

That was the message of four panelists during the Oct. 11 morning session of Hart Energy’s DUG Eagle Ford conference in San Antonio. Now that the play has reached the status of “one of the more prolific shale plays,” according to Bruce Matsutsuyu, vice president of exploration and production at Momentum Oil & Gas LLC, it’s time to take a step back to understand exactly what it is that Mother Nature has presented to the industry.

Matsutsuyu began his presentation by discussing the growth of the play in a very short time. “In three short years the Eagle Ford has just exploded,” he said, adding that the areal extent of the play has expanded from 415,000 acres in 2009 to 11.8 million acres in 2011. Of course this “expansion” is based on the industry’s understanding of the play. And while the understanding, and hence expansion, will continue to grow, increasingly it will take geologic understanding to maintain that growth.

For Matsutsuyu, one of the more exciting breakthroughs is happening at the molecular scale. In 2009, Robert Loucks from the Bureau of Economic Geology at the University of Texas published images of nanometer-scale pores found in the Barnett shale. The images were obtained using ion milling to create a flat surface on the sample, which was then examined with scanning electron microscopy.

This work has led to a preliminary classification of pore sizes, though more work needs to be done. But by using sequential images, scientists can see the kerogen and the pore spaces.

“It’s a huge advance,” he said.

Another important area of focus is understanding natural fractures, often caused by variations in the stress field. “With the Eagle Ford, we can create a natural laboratory,” he said.

Next on the docket was Dr. Peter Duncan, executive chairman of MicroSeismic Inc.’s board of directors (and founder of the company). Duncan’s company has helped pioneer the use of microseismic measurements during hydraulic fracturing to determine the size and orientation of the fracs.

Duncan said that three “communities” use microseismic data. The first community is completions engineers, who use the data to avoid mechanical failures such as poor cement jobs and geological failures such as fracturing into a fault. The data is also used to improve treatment efficiencies, which leads to reduced water use and other cost savings.

Secondly, the development team is concerned about geological risk, geomechanical insight, and recovery insight. To this end, companies like MicroSeismic take the well events, place them into a geocellular model, populate the model with amplitude events, obtain a resulting stochastic fracture set, and output permeability calculated from discrete fracture network observations.

Finally, to the operator, microseismic data provides transparency. By showing exactly where the fractures are propagating, operators can establish a level of comfort and rapport with landowners and other stakeholders.

Galen Treadgold, vice president of Global Geophysical Services, said his company also is using geophysics to map fractures. Global has shot 6,500 sq km (2,500 sq miles) of mostly compressional-wave seismic data to build a regional library and examine regional trends. And while many operators feel that geophysical information is not necessary in shale plays, Treadgold offered an eye-opening cost comparison: next to completion costs, which near the top of a bar graph, and drilling costs, which soar above it, seismic is “in the food services area” in terms of overall costs, he said.

“Not drilling into a 50-ft fault pays for three copies of our seismic data,” he said.

Global uses the data to invert for rock properties and also acquires microseismic data to understand rock property variations.

“The Eagle Ford covers 1,000 sq miles,” he said. “There’s huge variability. The faults need to be integrated into the development plan.”

Finally, Norm Warpinski of Pinnacle, a Halliburton Service, discussed the use of technology to optimize stimulation and completions. Pinnacle uses a dense array of tiltmeters to measure surface micro-deformation induced by fractures. By migrating the deformation back to the subsurface, Pinnacle scientists are able to determine the stimulated reservoir volume and frac components, he said.

Echoing Duncan, Warpinski said that sometimes this type of monitoring can allay fears of aquifer contamination – the shallowest fractures are still 915 m (3,000 ft) below the aquifers. And for those who characterize hydraulic fractures – correctly – as mini-earthquakes, Warpinski said that the largest events measure zero on the Richter scale.

“It’s a complex region requiring an integrated technical solution,” he said. “We’re combining different mapping technologies to aid in development. It shows we know what we’re doing.”

Contact the author, Rhonda Duey, at