Hard As A Rock - What Makes Shale Different

“What makes shale different?” was the question raised by Baker Hughes’ Adrian Topham, Product Line Manager for Reservoir Development Services, in a pre-conference day at Shale Gas Eastern Europe 2011 in Warsaw, Poland.

He explained, “If you look at conventionals in terms of age, brittleness, etc. we’re in the kind of granite region,” he said of shale. “Moving from resources to reserves, were very much at the early stages and can’t say we have reserves until 2014 plus.”

Total organic content and thermal maturity, he said, were key to assessing potential, as was understanding where to place the wells regarding exploration. To maximize total ultimate recover, multiple stage fracture modelling and reservoir production forecasting were two of his suggestions.

Topham questioned whether re-stimulation could help produce reserves.

“We’re at the appraisal phase,” he reported. We’re trying to characterize mineral composition, Kerogen type and maturity, and the geomechanical characteristics. Rocks breaking differently is an interesting issue to explore.”

Topham showed a slide of unconventional play mineralogy, a triangle, plotting of various North American shale plays. He said it was possible to plot out European plays and characterize them.

He said: “Acoustic measurements are a key in order to understand the geomechanical characteristics, as well as coring. We’ve now got a tool which gives you three times to the volume to do the measurements. If you’ve gone through it you can go back and catch some of the characteristics you’ve missed.”

Baker Hughes’ “FLeX” tool (a carbon measurement tool) and “RockView ™” (to enhance reservoir interpretation) services were mentioned.

“A formation lithology tool gives lots of cationic measurements to get a lot of detail to see how they behave with certain types of fluid. With an NMR tool, we can come up with fluid typing information to characterize the type of clay,” he said.

He said it was not only to acquire data but to mix and match and could be used in preparing for the fracturing stage by using real time geomechanics. “For mini fracks you can get some idea of how that rock is going to frack.”

Topham continued: “In the completion phase, down the road you’ve got to think about the interplay between the data you acquire early on - getting ‘logging while drilling’ (LWD) helps you determine where the zones are, where the natural fracture patterns are.”

He explained there could be sweet spots even within that very tight rock. “In the Baker Hughes sense we’ve got tools for positioning,” he added.

For “staying on target” he spoke of AutoTrak, which he said could save drilling time and place a drilling operation in the sweet spots.

One participant offered that “brute force” had been used in drilling in the Bakken shale and that a nuanced approach was going to be important in Europe.

Topham contended that the data acquisition part should be married with drilling technology. “The designing of how you can complete the fracture is key.”

He spoke about an open-hole completion system called FracPoint.

In terms of European shale basin geology, Topham said: “Most are aware of the different activities in Poland. There’s been a massive land grab. In December a couple of wells were drilled, now there are probably a dozen. Seismic is being shot. Dry versus wet gas options are available.”

Frac fluid types he said had yet to be confirmed.

After a break, Mr. Topham continued by discussing hydraulic fracturing design.

Verticals, he said, were cheap to drill, and were easiest to fracture and required lots of well bores, especially versus horizontal.

“Frac fluid transfers energy and transports and suspends the proppant. It needs to be compatible with formation minerals; you want to minimize damage to your proppant,” he said.

It must also be environmentally friendly, he said, and easy to use.

“How much of a frack fluid do you get back?” he queried “30-60%? We want to get 100% re-use and were working on a project to get that in the US. We want to re use as much water as possible.”

He said frac experts could provide some rules of thumb: “When should I use CO2 or N2 in low pressure formations? We can’t just use water all the time.”

Shale gas, and natural fractures were essential, explained Topham, who said treatments were designed to connect up natural fractures and leave them propped open.

He added that regulations were a major concern for the industry in Europe, and the reason the French government had shut down hydraulic stimulation.

In that context, Topham gave mention to “REACH” a European Community regulation on chemicals and their safe use.

Regarding the contents of fracking fluid, he said: “Baker Hughes fully supports the mission of the European Chemicals Agency, ‘ECHA’. You have proprietary mixes, and the REACH system basically allows them to be given to an independent lab which can certify their safety, giving the info to regulatory agencies without sacrificing regulatory knowledge.”

Slick water fracturing was not a panacea, according to Topham, who admitted it was cheap, had quick fluid recovery, and operationally simple. “It works well in very low permeability shallow formations, but can’t be used to transport medium to high density proppant systems.”

Finally, one of his slides showed a typical fracturing location. “This is an operation in Europe,” he explained. “Usually there’s a big North American spread – you can get a lot of equipment into a smaller area, so this is an example of how it could be done in other parts of the world.”