>Wonder how many fracs they had to do :)

Hey LP, back in 1931 they used the hammer :)

“Stimulation has evolved from horsepower to precision.”

Kent Perry, Director of Exploration and Production Research, GTI

“Stimulation has evolved from horsepower to precision,” said Kent Perry, director of exploration and production research with GTI. In the 1960s, an experiment with nuclear stimulation showed that technique “was not practical for a lot of reasons,” he said. Hydraulic fracturing then became the tool for developing low-permeability reservoirs. In the Denver-Julesburg Basin in Colorado, for example, the strategy was to drill one well on 640- acre spacing and perform a massive hydraulic frac in an attempt to drain a significant portion of that rock. Stimulating tight sand reservoirs with cross-linked polymer fluids and large sand volumes often was too expensive.

In the 1990s, the less-costly slick-water fracturing technique that used large volumes of water and low concentrations of proppant made more prospects economical. Then the development of multi-stage fracturing made it possible to more efficiently treat several zones. As more was learned about fractures, it became clear that the ability to reach all the rock with 640-acre spacing was limited. “Fractures were short and taller, and more complex,” Perry said. The key to success is to get a wellbore into the vicinity of the rock that is to be produced. With the limited ability to reach out with a frac treatment, the sands have to be reached with a wellbore instead. An example is the Jonah field in Wyoming, Perry said. Spacing as low as 10 acres per well is being considered to adequately drain the gas from that reservoir. With horizontal drilling and microhole wellbores, it is practical to access reservoirs with small well spacing. “We hit it with a hammer in the 1960s,” he said. “Now, we are using a much lighter touch.”

Still, hydraulic fracturing of low-permeability zones is complex. Tight gas sands have a wide geographic spread and vary in depositional environments, subsurface stress regimes and reservoir properties. Predicting and characterizing natural fractures in low-permeability sandstones is difficult; a fracture design that is successful in one field may not be in another. Introducing a water-based fracturing fluid into a low-permeability reservoir can lower the effective frac half-length because of phase trapping associated with the retention of the water-based fluid in the formation. The problem is magnified by the water-wet nature of most tight gas reservoirs where no liquid hydrocarbon saturation has been present. Retention of this increased water saturation in the pore system can restrict the flow of methane. Use of water in reservoirs with low saturation may also reduce permeability and associated gas flow by permanently increasing water saturation.

Another significant issue in tight sands reservoirs is permeability reduction resulting from physical and chemical reactions between the reservoir rock and the drilling and fracturing fluids. Better fracturing technology has made possible increased production from tight sands during the past two decades, but several challenges remain to be met, according to a GTI report on unconventional gas technology needs. For example, because hydraulic fractures normally grow parallel to the open natural fractures, they intersect only a few of the open fractures, limiting flow rates.