SAN ANTONIO—U.S. oil and gas drillers have made strides in successfully unlocking hydrocarbons from shale basins, but there is still work to be done when it comes to hydraulic fracturing efficiencies.
About 80% of fluid pumped into the ground does not contribute to production, according to William D. Von Gonten Jr., president of W.D. Von Gonten & Co., a Houston-based company that provides petroleum engineering, geological services and petrophysical modeling.
“Our biggest low-hanging fruit is the stimulated rock volume. That’s where our inefficiencies are,” Von Gonten said Sept. 13 during Hart Energy’s DUG Eagle Ford conference. “If I can make the stimulated rock volume just 10% better, it’s linear; I’ve increased the productivity of the well 10%.”
Although permeability, porosity and fluid viscosity play important roles in production levels, pressure and stimulated rock volumes matter more when trying to get the most out of hydraulic fracturing efforts, according to Von Gonten.
In certain parts of the Eagle Ford, ash beds and calcite layers, which are not visible on openhole logs, impact the effectiveness of fracture designs and lateral placement. But high-resolution logs and cores are shedding light on the issue, and the insight on rock could lead to better designs, greater stimulation and ultimately, more production, as operators continue seeking efficiency gains.
Showing a 75-ft cross-section of rock spanning from Webb County to Dimitt County to La Salle County, which are all in Texas, Von Gonten illustrated how the presence of multiple layers of hard calcite beds next to soft ash beds—along with their contrasting mechanical properties—presents hydraulic fracturing challenges and drives the complexity of fractures.
Using a high-resolution fracture model simulation, Von Gonten showed how the height of a penny-shaped frack changed as calcite layers were added. As the number of rock layers increased, the fracture height decreased but the fracture length increased. Such knowledge could prove beneficial for spacing.
Take, for example, 120 ft of the Eagle Ford with no layers. Drillers can get the height and length needed to drill wells on 300-ft spacing, Von Gonten said, referring to modeling lab work. If calcite and ash beds are added to the same 120 ft, the fracture height may not be as high but the length may be twice as long, requiring 600-ft spacing. This occurs despite the rock having the same porosity, saturation, pressure and viscosities.
“We all have the models to do it, but we have to input the models with the correct data,” he said. “We’ve been inputting models with average data that doesn’t represent the rock.”
Weak interfaces, particularly near calcite layers, and leak-off are also areas of concern. When a frack hits a calcite layer after moving though mudstone, the fracture length will be wider in the mudstone and narrower in the calcite layer, resulting in leak-off and fluid loss down those layers, Von Gonten explained. He pointed out how W.D. Von Gonten & Co. built a model and input layers to analyze how changing properties impact fractures. The higher the leak-off flow rate, the lower the flow rate in the fracture.
So how can drillers get more effective prop-connected fracture height?
For starters, Von Gonten suggested selecting a proper landing zone, perhaps near calcite beds. “If I’m pumping 25 barrels per minute per cluster and those calcite layers are right next to me, they are a non-issue; I’ll blow right through them,” he said.
Closer cluster spacing and stimulation designs incorporating ash bed fluid sensitivity and fluid leak-off measurements for weak interfaces, while also reducing interface leak-off and maximizing widths with proper sand loading, were also on his list.
“Now that we have a model, we can put it all together to really understand it,” he said, later adding there is more work ahead. “I think our recovery factors are 15%+, but I think we are draining only half of what we think we’re draining in specific areas, not the whole play. So there is a lot left to do.”
Velda Addison can be reached at email@example.com.