Shales: Let’s Get Petrophysical

Characterizing shale reservoirs one topic among several at shale gas workshop

When you’re one of the world’s biggest services suppliers to oil and gas drilling operations around the world, you probably know a thing or two.

And that’s why experts from Schlumberger Limited offered their insights and experiences to participants in a one-day workshop preceding Shale Gas World 2010 in Warsaw, Poland.

Rick Lewis was one of them. Schlumberger’s Technical Projects Leader-Petrophysics in North America, he talked about Reservoir Characterization: Heterogeneity and the Core.

“Our goal is to take the knowledge we’ve developed in the US and apply it elsewhere to get up to speed as quickly as possible. I’ve seen some outstanding shales outside of North America. The rules of geology are staying quite consistent,” he said.

“What is an organic shale?” asked Lewis. “It’s the most common sedimentary rock – they’re source rocks, deposited in an environment where there was little or no oxygen. The carbon wasn’t broken down, it was buried, cooked, and ultimately created oil and then gas.”

He noted that in North America conventional reservoirs for natural gas were “all done.”

“We keep finding new shales all the time in North America, there seem to be more and have more in common.”

Lewis showed the audience a photograph of a shale outcrop.

“They’re almost always extremely heterogeneous,” he said. “They’re continuous horizontally but highly heterogeneous vertically. There are good zones in these shales and bad zones.”

He explained that upscaling from core samples to log and then to seismic data was proving invaluable to Schlumberger’s shale gas drilling operations. According to Lewis, when a shale is cored it looks like a hockey puck.

“When we start looking at different cores you start seeing there are differences in shales: darker, lighter, or highly laminated. There’s a lot of variability in mineralogy. Subtle variations in clay types can lead to huge differences.”

Lewis added, “The majority are siliceous, which means they’re easier to complete. The Marcellus is argillaceous – it’s extremely economic, while the Barnett is the grandfather of them all and is much less clay rich. The clay rich zone in the Barnett is the best zone there (argillaceous); and the calcareous zone of the Haynesville is the best there.”

He contended that the perfect shale was approximately 25% illite.

“The one thing all of these shales have which makes them unique is their organic matter – a mixture of carbon and hydrogen,” Lewis explained. “As it gets more mature it creates its own porous network. The mineral matrix is really forming a framework that supports the porosity that we see in the kerogen. You’re typically looking at 3% TOC which is about 5% kerogen. These rocks are extremely organic rich.”

He continued, “It’s really critical to put your core plugs in the right place. It’s better to have an automated system, because then you know about both the best and poor quality rocks.”

Via cluster analysis, Lewis said it was possible to get a representation of all the different rock types. “It’s really important to get the full variation to do much better calibration.”

He said that sidewalls could tell drillers if  a shale reservoir was good.

“Once you have a cluster type understanding you can start actually plotting out where you have good rock and where you have bad rock. It can be upscaled quickly,” he said.

Next up was George Waters, Shale Completions Technical Manager for Schlumberger, whose talk was entitled Gas Shales Petrophysical Evaluation.

“We’ve evaluated lots of wells around the world,” he said, “so we can tell you whether you have an adequate reservoir.”

Waters spoke about how it was possible to flow hydrocarbons through a pore system, looking at a gas shale that was part of a conventional sandstone.

He said, “There are two kinds of porosity – organic in the kerogen – and the other kind is in the clay, the quartz, etc. which we don’t care about because we can’t produce from those.”

“Our goal is to find a shale that’s full of gas and connected, that makes it permeable. We didn’t even know this three years ago; now we can get an image of what the rock really looks like,” added Waters.

To put shale in perspective, he offered comparisons of permeability, showing that shale is somewhere between brick and cement. “Generally if it’s less than 100 nanodarcy, it’s not producible.”

Waters said it was all about identifying the best reservoir that can be completed, because it was all about completion.

“Mechanically the Barnett is outstanding,” he said. “We thought George Mitchell was crazy but it took their persistence there, because it was 20% clay, extremely siliceous, and not as organic rich as some shales. If you have high water saturations, these rocks don’t work.”

He said that the Barnett shale was not the most permeable, but that it was possible to do a great frack there. Waters said, “It’s all driven by the clay.”

“The Haynesville has high clay, and petrophysically it’s better but typically the decline there is 80%. It’s coming on strong, but closing down quicker.”

He said that vertical variations led to huge differences in how those wells performed.

Waters spoke extensively on shale gas evaluation needs, covering things like delineation of shale gas beds, quantifying gas in place, and lateral landing points.

“Every play we do is drilling horizontal wells, and where you put it is critical to the producibility. We see huge variability within one mile. It depends on where you land the lateral.”

He addressed the question of “What makes a good reservoir?” and said it came down to four criteria: effective porosity 4-12% (effective phi); low water saturations (less than 45%); permeability of greater than 100 nD; and TOC greater than 2 wt%.

“Everything we’ve seen that’s been productive has been type 2 kerogen,” noted Waters. “It’s generally good from a kerogen perspective but bad from a clay perspective.”

He said he hadn’t seen type 1 kerogen that had worked. “I don’t see a reason why they won’t work, you need low clay content to complete it. It depends on how long it’s been in the oven.”

Waters showed attendees a graph that depicted the higher the organic carbon content, the higher the permeability, and spoke about pore spaces.

“If a pore is lined with kerogen, water doesn’t want to be there. When we’re pumping giant slickwater jobs, water is being electrostatically replaced. An extra layer of water means it’s difficult to get anything out of it, because kerogen is hydrophobic.”

Waters spoke of shale’s mechanical properties, showing an American Oreo cookie – a layered sweet with cream in the middle - to demonstrate. “Because of lamination, shales are very strong horizontally – it’s twice as strong as it is vertically.”

He recounted a spot in the Barnett shale, about 15 miles from a good area. “By changing the lateral landing point made a non-productive well into an economic well. We have to find those best intervals and stick with them as opposed to an ’it doesn’t matter, we’re going to frac them anyway’ attitude,” he concluded.