Despite the huge volumes of oil and gas being produced from shale deposits, there’s still much to learn about these unconventional reservoirs, which have the added role of being source rocks.
They persist in challenging even the most experienced geoscientists and operators.
Unfortunately, quantitative seismic interpretation workflows continue to be immature for these reservoirs, compared to carbonates and clastics.
“With unconventional shale gas and oil, you have to know the rock quality, whether the rock is brittle or not in order to fracture the reservoir,” said Gabino Castillo, North America services and software manager at CGGVeritas in Houston.
“Also,” he continued, “if it’s brittle, we need to know how the fractures will propagate.”
Surface seismic data and microseismic data both are key assets for many companies producing from unconventional resource plays.
And there’s good news in that recent advances in pre-stack seismic data analysis yield attributes that appear to correlate to lithology, rock strength and stress fields in the formation, according to Castillo.
“Knowledge and proper utilization of these attributes may prove valuable in the optimization of drilling and completion activities,” he said.
Tweaking With Purpose
Castillo has been involved in a number of projects to hone his expertise in the newest techniques to characterize and understand unconventional reservoirs. Much of this work has focused on the well-known Haynesville shale gas play in North Louisiana.
Evolving out of this study effort is an integrated seismic approach based on pre-stack azimuthal seismic data analysis, microseismic and well log information to identify sweet spots, estimate geomechanical properties and in-situ principal stresses.
With a tweak or two, the technology approach garnered from the studies can be applied to other formations – given that the challenges to be resolved are the same, more or less.
“The weight we put on each individual technology is different,” Castillo said. “Sometimes the most important is TOC, sometimes brittleness, sometimes fracing – it depends on the case.”
He noted the importance of properties such as Young’s Modulus (measure of elasticity of a rock or other material) and Poisson’s Ratio (measure of how a rock is going to deform in one area relative to another).
“These may provide valuable information for facies identification, mineral content and rock strength,” Castillo emphasized. “From these, we may infer preferential sweet spots.”
He gives high marks to the opportunity for validation and calibration of the work.
“We have inversion, all the elastic attributes, anisotropy, etcetera, etcetera,” he noted. “The one piece that was always missing before was the validation, calibration, the microseismic.
“I had microseismic data, cuttings, SEM mineralogy analysis. So I had textural mineralogical data we used to estimate brittleness, which is useful for well completions,” Castillo said. “We had the opportunity to calibrate all the seismic properties with hard data.
“On top of that, with microseismic data I found interesting correlations between size of the stimulated reservoir volume and Young’s Modulus,” he added. “So I found a positive correlation in that.”
Putting It Together
Castillo assembled a summary sketch of the key ingredients for shale reservoir characterization.
“Integration between surface seismic, microseismic data, mineralogy, production data – how to put everything together – is essential for unconventional reservoir characterization,” he said.
He elaborated further.
“The way I see it, you have seismic data and it gives you pre-stack inversion, azimuthal attributes, fractures.
“From the microseismic you have location of event, magnitude and the stimulated reservoir volume.
“With the mineralogy, you have reservoir quality, geomechanical properties.
“Using production data, you have, for example, sweet spot maps, which are really important.