What Makes a Good Gas Shale?

Schlumberger has the answer

Doug Bentley, European Unconventional Resources Manager at Schlumberger says that his company has evaluated over 1200 shale gas pilot wells, evaluated more than 30 North American shale basins, and 15 more outside of North America.

“What Makes a Good Gas Shale” – was the title of Bentley's talk at the Global Shale Gas Forum in Berlin, Germany.

Based on what he called “horizontal production logs” Bentley spoke about the key parameters for good shale. “On the geology side from what we’ve done, the key things we come back to are: having the gas in place, permeability, organic richness, thermal maturity, and reservoir pressure.”

On the engineering side, he said frac containment, conductivity and compatibility were crucial.

One of his slides showed the mineral framework and pore system of both conventional sandstone and shale.

“If you put conventional sandstone up against an organic shale, the latter has much more complexity to it. It’s the kerogen (an organic material) where you find most of the pore space,” he explained.

“In the Barnett, permeability does matter – it makes for a better well,” said Bentley. “It can result in a doubling of well performance. So, yes, it does matter.”

Perm vs. saturation was also a topic he touched upon.

He said, “Higher clay volumes bring up higher saturations. As the saturation goes up, the permeability comes down. We have data from a lot of wells – you can see the plot shows an increase of permeability; higher TOC and clay volume. Then, you’re shutting down the system.”

Bentley explained, “That’s why you have to understand where to place the laterals.”

He also talked about what he termed “Wettability” - hydrophobic versus hydrophilic (i.e. does it like water or not?).

“Kerogen is hydrophobic, which is good for us,” said Bentley. “If you throw a piece of shale in a bucket of water, it starts bubbling and everyone gets excited.”

“These are very highly laminated by nature,” he explained. “You’ll find systems that are clay rich. If you look at them in a vertical sense, when you try and stimulate these rocks you’ll have permeability layers that exist within the system.”

“It’s important to know what this rock looks like and how it’s going to break,” Bentley said of shale. “It can be very anistropic due to laminations. Vertical and horizontal shears are not the same.”

Bentley said a shale could be a bit like an Oreo cookie: “The difference between these stresses can be great. You need 3-d shear measurements, as calculating the stress can make a huge difference.”

It depends on the vertical variability of the stress, he said, reporting,

“Changing the placement of the well bores can actually double the IPs.”

Bentley went on to explain his “economic shale gas conclusions.”

“The gas is in place, it has good matrix permeability, and conductive hydraulic fractures of adequate height and surface area. These are all driven by TOC; clay content and type; and vertical distribution of clay minerals (anisotropy). Understanding where you can place these well bores is key.”

“These are good concepts, the models are there, there’s a tremendous amount of data,” said Bentley.

“In Europe there’s the challenge that there’s not a lot of data – there will be huge areas and decisions will have to be made in 3-5 years. ‘Keep drilling or move on?’”

“This needs to be tied in to seismic to identify the sweet spots. If you can evaluate a certain area rather quickly, you cut your risk as quickly as possible. The resource can then be quickly evaluated,” he concluded.

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