As the reality of falling profits and a global supply-demand imbalance force the oil and gas industry to become more efficient, companies are increasingly turning to technology.

When it comes to maximizing the potential value from hydraulic fracturing in unconventional resources, seismic—specifically, ambient fracture imaging—is getting attention.

When a company ran into problems cracking rock for proppant placement, the new seismic technology proved to be helpful in devising a new pumping strategy for the unconventional reservoir, according to Global Geophysical. After collecting ambient seismic data, which is used to evaluate reservoir conditions before, during and after well completions, the geoscience company performed a stress inversion on the imaged fracture network data.

The findings revealed stress at the wellbore.

“This information was used to modify the completion strategy, and proppant was successfully placed in the remaining stages,” Global Geophysical said in a case study. “The frack-time activity imaged differences between stages at the toe and heel of the wellbore.”

As described by Global Geophysical, ambient seismic technology transforms microseismic from a well completions evaluation tool to a predictive one.

“Using proprietary processing techniques, ambient seismic reveals the geometry and extent of natural fracture networks; the size, orientation and complexity of induced fractures; the volume of rock activated during stimulation; and the volume of rock active during production,” the company said. Data, which can be collected while acquiring traditional 3-D seismic, are recorded with a surface array or with a buried array.

In this case, the process focused on using pre-frack data to improve the completion design. Prior to the scheduled completion, a hexagonal surface array spanning 7.5 sq miles was deployed to get three days’ worth of ambient data.

The array was deployed again a month later to the original locations with the exception of areas impacted by river flooding before data processing began.

The process involved use of a velocity model, trace processing to remove noise and the application of statics.

“A volume of interest surrounding the well was defined and divided into sub-volumes called voxels. A table of one-way travel times was computed from every voxel to every receiver,” Global Geophysical explained in the case study. “The processed signal was streamed through the depth imaging algorithm that sequentially focused each time step into every voxel being imaged. The focusing for each time step, for a single voxel, requires time-shifting each trace based on the travel times from the voxel to each receiver.”

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Images of the time steps were then stacked, giving depth to the time window for the pre-completion fracture map. “This process was repeated for field data collected during the completion,” the study said.

The completion design, customized with optimized perf locations, was made possible thanks to the natural fracture map that pointed to highly fractured rock.

“The size, orientation and activity level on the mapped fractures were used to perform the slip-tendency stress inversion,” Global Geophysical said. “This stress information informed a revised pumping strategy that resulted in successfully breaking rock and placing proppant in the remaining stages. Having a map of the natural fracture system and the local stress state allowed for a more efficient and successful completion.”

Velda Addison can be reached at vaddison@hartenergy.com.