Technical strides in geophysics have been numerous and impressive in recent years. But there are a few folks who think the industry might be making too many strides and not necessarily in the most important directions.

At the recent annual meeting of the International Association of Geophysical Contractors, several operator and service company representatives were asked to give their thoughts about subsurface imaging challenges. John Etgen, distinguished advisor, seismic imaging at BP, got the ball rolling by calling into question nearly everything that geophysicists hold dear.

Etgen said that the objective for the future is a quantitative model of the subsurface, where data “almost interpret themselves.” But getting to this point will require doubling the resolution of current seismic images and identifying more believable attributes. Advances such as wide-azimuth acquisition “have given us better pictures to interpret but not necessarily more quantitative information,” he said.

Furthermore, Etgen said, the industry has not made significant progress making good use of the new redundancy in its images.

New targets for seismic investigation also require better representation of properties like lithology, pore fluids, reservoir performance, and stress state. “Seismic is only giving us hints about these things,” Etgen said.

“Maybe the things we are going after aren’t the things we can get,” he said. “The future is wide open in the sense that we can break paradigms and revolutionize geophysics.”

Ken Tubman, vice president of geosciences and reservoir engineering for ConocoPhillips, had similar issues about geophysical measurements in unconventional plays. “In structurally benign areas such as unconventional reservoirs we need to get at reservoir properties like anisotropy estimates and rock properties,” Tubman said. “We’re spending more than [US] $5 billion this year on the unconventionals and almost nothing on seismic. Contractors are delivering very few answers that we need beyond simply locating the reservoir.”

In one experiment Tubman’s company used prestack depth migration to remove fault shadows and saved significant money by being able to simplify the well construction. However, he said there is much more that can be done. For instance, ConocoPhillips went from near zero production to 100,000 b/d of oil in the Eagle Ford in just over two years. “We expect that to continue for decades,” Tubman said. “But what else can we get out of it? Where is the best part of the shale?”

He added that while the company spends a great deal of money on drilling and fracing, engineers would benefit from additional methods to know if their results are optimized. “We are using seismic for location of reservoir intervals; that’s a fairly basic objective,” Tubman said. “We need techniques that point to the best places to drill, identify the true area stimulated, and allow us to most efficiently develop the resources.

“We need to reinvent our studies with shales rather than sandstones. It might be very different. Now we’re just borrowing old ideas.”

The majors continue to drive the demand for new geophysical technology. Based on these comments, it looks like contractors won’t be resting on their laurels any time soon