How sweet it is

Horizontal ‘Fracs’ Yield Statigraphic Surprises

It often appears as if the majority of the population worldwide is yakking about hydraulic fracturing.

There’s good talk and bad talk.

But despite all the chatter about hydraulic fracturing, which typically is done in horizontal wellbores, there’s not yet been any fanfare about some pretty cool stuff going on that can impact application of this technology.

The general thinking is that you drill a well down to a determined hydrocarbon-bearing zone and head out laterally with the drill bit with the idea that everything is the same along the sideways leg.

“Frac” jobs are implemented at specific intervals.

Sometimes that’s a good idea, sometimes not.

It’s now been shown that the “sweet” aspect of an identified sweet spot can change – not only stratigraphically, but also laterally within the zone itself.

“Sweet spot is a term that is loosely defined,” said AAPG member Stephen Grimes, senior staff geologist at Empirica, a division of ALS Oil and Gas. “This is due to many contributing factors, such as TOC, payzone thickness, thermal maturity, fracture density and spacing, brittleness, clay content, nature of porosity and so on.”

The common method of fracturing throughout a lateral, where the zone is actually heterogeneous, yields production that is a concoction of different geochemical components.

“We can show evidence that horizontal wells commonly show significant heterogeneity through the lateral, for whatever reason,” Grimes noted.

“This is seen in the gases liberated by drilling, as measured by direct quadrupole mass spectrometry (DQMS),” he said. “The clear differences observed enable laterals to be zoned in terms of prospective oil, condensate, gas, water-saturated or non-productive zones.”

The implications here are heavy duty.

If you determine that a lateral “mini-zone,” so to speak, is non-productive, then you can eliminate a frac job in that section, saving considerable time and perhaps a quarter of a million bucks, give or take.

On the other hand, if you’re after, say, oil and maybe condensate, the frac jobs can be limited to only these potentially rewarding zones identified in the lateral.

It’s a Gas

Grimes is quick to note that many laterals are pretty much homogeneous, with the targeted zone emitting essentially the same geochemical signal throughout.

Where heterogeneity enters the picture, it’s essential to rule out that it’s due to a change in stratigraphic levels owing to geosteering issues.

It becomes a matter of determining how much of the zonation actually correlates to geochemical zonations.

“The main criterion refers to the heaviness of the population of gases we’re analyzing in the mass spectrometer,” Grimes said. “For instance, if we start getting a lot of heavier alkanes, like C-7 through maybe C-10, then it begins to look like an oil-bearing zone.

“We also look at different ratios of methane or propane to other gases,” he noted. “This is kind of an extension of methods used successfully since the ’80s, using gas chromatography data to figure out if it’s oil or gas.”

He emphasized they interpret what they’re in from gases coming up through the drill stem, which is basically the same idea as mudlogging and clarifying the gas.

“On our main test well, the geosteering image shows how we traversed the section through the lateral and tied that to the mass spec data, showing that some heterogeneity is going on from a lateral well scale,” Grimes noted.

Something on the Light Side

Along with the gases being measured from the drilling mud, the team also is looking at some of the lighter elements and inorganic compounds in the vertical pilot well, especially for questions related to permeability or seal quality.

“We’re looking at helium mainly because that’s the smallest element that’s going to be an indicator of seal quality, but also hydrogen and carbon dioxide,” said AAPG member Josh Dill, remote operations manager at Empirica.

“In geosteering, we prefer to have data from a pilot well for comparison so we see things in stratigraphic order and know that from this different horizon we’re getting this sort of chemical signal and this kind of gamma ray signal,” Dill noted.

“A lot of our work on mass spectrometry is more for vertical pilot wells when they’re cutting through stratigraphy, and this gives us ideas on geochemical changes as they go from bed to bed,” Dill said. “If working on laterals, we have some basis of what to expect in that part of the formation.

“Since we’re dealing with heterogeneity at the small scale of well versus basin scale, it’s important to have a pilot hole and kick off from there to do the lateral,” he emphasized.

“We have all different types of data related to just that well, so we’re studying to tie those together and see the geosteering/gamma ray data in conjunction with mass spec,” Dill said. “When Steve started to do that, he came up with some good theories and questions about heterogeneity.”

The Homogeneous Zone

The old method for using mass spectrometry and geosteering is that they are run independently and analyzed separately. The geosteering effort assumes that what is seen on the pilot hole is correct throughout the lateral – in other words, the zone is homogeneous.

“The new style is what can we do, what can we improve,” Dill said. “That’s what we’re seeing by using mass spectrometry data while actually doing the well and merging the two sciences rather than analyzing them both at the end.”

He noted several examples of wells illustrating lateral zonation, one of them being the Cretaceous Tuscaloosa Marine Shale (TMS) in Mississippi.

“The well is strongly zoned for indicators of condensates and oil,” Dill noted. “In order to verify that these zones reflect actual lateral differences within the target strata and not movement above or below the target, we re-geosteered the TMS lateral to see how much it had cut up- or down-section.”

They verified that despite some movement of the bit, the zone contacts rarely correlate with expected stratigraphic contacts, and the zonation doesn’t correlate with stratigraphic order.

“In other words,” Dill said, “the hydrocarbon zoning is at least partly non-stratigraphic.”

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Emphasis: Downhole Geology