Understanding the Interplay of Natural and Induced Fractures

If a taint exists on the use of geophysics to evaluate fracturing operations, it is this:

‘T ain’t easy.

In fact it’s downright difficult, said Arash Dahi Taleghani, associate professor of petroleum and natural gas engineering in the Department of Energy and Mineral Engineering at Penn State University.

Dahi Taleghani’s research areas include studying how natural fractures can affect hydraulic-fracture geometry and using seismic for modeling natural fractures and post-treatment fracture analysis. That work becomes more challenging as fracture complexity increases.

But, “the point is, it’s fracture complexity that allows us to produce more oil and gas from the formation,” Dahi Taleghani said.

Unconventional reservoirs – especially shale reservoirs – tend to be heterogeneous, with different characteristics in different directions. That leads to seismic anisotropy as direction affects seismic wave velocities.

When using seismic to assess fractures, “anisotropy needs to be considered, and another thing that needs to be taken into account is the amount of heterogeneity that exists” in the reservoir, Dahi Taleghani noted.

He and his fellow researchers also have found that diagenesis and mineralization can be important in evaluating the relationship between natural and induced fractures, especially in the case of cemented natural fractures.

“We take the diagenesis into account – this is important,” Dahi Taleghani noted.

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If a taint exists on the use of geophysics to evaluate fracturing operations, it is this:

‘T ain’t easy.

In fact it’s downright difficult, said Arash Dahi Taleghani, associate professor of petroleum and natural gas engineering in the Department of Energy and Mineral Engineering at Penn State University.

Dahi Taleghani’s research areas include studying how natural fractures can affect hydraulic-fracture geometry and using seismic for modeling natural fractures and post-treatment fracture analysis. That work becomes more challenging as fracture complexity increases.

But, “the point is, it’s fracture complexity that allows us to produce more oil and gas from the formation,” Dahi Taleghani said.

Unconventional reservoirs – especially shale reservoirs – tend to be heterogeneous, with different characteristics in different directions. That leads to seismic anisotropy as direction affects seismic wave velocities.

When using seismic to assess fractures, “anisotropy needs to be considered, and another thing that needs to be taken into account is the amount of heterogeneity that exists” in the reservoir, Dahi Taleghani noted.

He and his fellow researchers also have found that diagenesis and mineralization can be important in evaluating the relationship between natural and induced fractures, especially in the case of cemented natural fractures.

“We take the diagenesis into account – this is important,” Dahi Taleghani noted.

“Natural fractures are not always smooth and clean. You have some roughness that is possibly in the direction of the fracture propagation,” he said.

Depending on the interaction between hydraulic fracture propagation and cemented natural fractures, three outcomes are possible. The natural fractures might have little effect, or might even act as a barrier to propagation.

In a third scenario, however, an expanding hydraulic fracture can reactivate and extend natural fractures even without intersecting them.

“They are acting, actually, as a weak path for fracturing the rock,” Dahi Taleghani said.

A paper he co-authored with Jon Olson from the University of Texas-Austin found “when natural fractures are perpendicular to the direction of the hydraulic-fracture growth, the largest possible debonded zone may form, which is equivalent to the most optimum case to stimulate a reservoir.”

Because of this possible interplay between hydraulic and natural fractures, the paper concluded that “complex fracture-network modeling capability is an integral part of predicting well performance in the naturally fractured reservoirs that are common in unconventional plays.”

How to do that modeling effectively remains a question, even now.

Horizontal Transverse Isotropy

According to the seismic company CGG, given the target depth of formations in shale gas basins being exploited today, the maximum stress is vertical, giving rise to Horizontal Transverse Isotropy.

In HTI, the natural fracture system is comprised of vertical fractures which cause anisotropic effects on seismic waves as they pass through. The effects are observed as changes in amplitude and travel time with azimuth.

In those formations, conventional seismic information can be useful in stress measurements and in studying geomechanical properties, CGG said. To calculate stress values, linear slip theory for geomechanical properties is used.

“As seismic data measure dynamic stress, results are then calibrated to the static stress that is effectively borne by the reservoirs at depth, making it possible to predict the hoop stress and the closure stress as key elements defining the type and motion of fractures,” CGG said.

Useful geophysical tools include appropriate data acquisition and detail-attentive amplitude versus azimuth processing, as well as amplitude versus offset, interpolation and inversion.

“But the typical seismic cannot detect fractures because of the resolution of your seismic picture. However, you can see the difference that the anisotropy makes in different directions,” Dahi Taleghani said.

Microseismic in Unconventionals

The huge amount of data and processing time required to evaluate fracturing in unconventional reservoirs using conventional seismic also presents a problem, he said. So the industry has turned increasingly to the application of microseismic in unconventionals.

“With microseismic the data processing is a bit easier because of the size of the files and existing constraints,” Dahi Taleghani noted.

“We are basically listening to the noise from the hydraulic fracturing. Microseismic has flourished a lot in the past 20 or 30 years because of the shale revolution,” he said.

Using microseismic doesn’t produce ideal results in assessing fracturing operations, according to Dahi Taleghani. The signals tend to be weak, hence microseismic has a high noise/signal ratio, he said.

“Always, you have a large uncertainty in identifying the exact location of these events,” he noted.

He uses both kinds of seismic data in his research, with one goal being to place existing natural fractures within the context of hydraulic fracturing operations and estimate the results.

“Based on the data, we try to come up with an optimization algorithm to characterize these natural fractures,” he said.

Assessing the success of those efforts leans somewhat on conjecture. To evaluate the effectiveness of their models, researchers need detailed, real-world production data and production results, information that operators do not release.

“You need to have extensive production data, which is unfortunately not available because the companies are very careful about their proprietary data,” Dahi Taleghani said.

So researchers use known data, statistical projection and other tools to create synthetic data sets “for examining the robustness of the proposed workflow,” he explained.

“We can use these synthetic data sets to reproduce the natural fracture sets. In this sense, it was successful,” Dahi Taleghani said.

Getting to a truly effective, broader application of geophysics to fracturing analysis obviously will take increased cooperation between industry and researchers, he said.

“I think more support from the industry can open the way. And this will also help them” to improve current technology and increase production, Dahi Taleghani observed.

But because of the lingering effects of the recent industry downturn, “it has become very difficult for these companies to commit to a research project, or even to provide any money,” he said.

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