SAN ANTONIO─Operators who want to stay profitable in the Eagle Ford during a downturn need to drill and complete in a smarter manner. According to Daniel Mohan, senior vice president of marketing for Ayata, prescriptive analytics can help.

Mohan spoke as part of a technical panel at Hart Energy’s DUG Eagle Ford conference in late October. His talk, “Completions innovations that make $40 oil work,” described the role prescriptive analytics can play in wellbore placement, completion design, “quantifying intuition” and the ability to apply synthetic variables to circumstances that can’t be controlled.

“Prescriptive analytics predicts the future, tells you what you need to do to make that future a reality and gets smarter the more you use it,” Mohan said. “Operators in unconventional resource plays are using it to create better recipes for drilling, completing and producing wells.”

He gave three examples of where conventional wisdom doesn’t always stack up. The first was, “Close enough isn’t good enough.” Wells that are drilled quickly often miss their target zone, and two wells with identical completions might be quite different in production rate.

“Drilling inconsistencies, while subtle, matter greatly in ultimate production,” he said. “A difference in targeting of 75 feet could drive a dip in production of about 20% after 180 days. It’s pretty significant.”

The second adage was, “Bigger isn’t always better.” This relates to completion design. Mohan said that one of the advantages of using prescriptive analytics is that it’s not limited in the number of variables it can consider.

“We’re looking at the near-wellbore geological variables and trying to find an explanation for variations in production,” he said. “We started looking at different completion designs and the result was tighter, shorter stages; tighter cluster density; more clusters per stage; and more sand.”

He used the analogy of weaponry. Back during the Gulf War, the daisy cutter was a weapon of choice. It was indiscriminate but powerful. Today, he said, an F-16 can place a bomb through a 2-foot window.

“Today we’re seeing better results when completions are designed to maximize the contact with the reservoir,” he said.

Finally, the concept of quantifying intuition includes building the impact of elements that operators know will have an influence on production but that can’t be measured or controlled.

Some of the analytics that Ayata can provide to operators include a proximity depletion feature, which uses distance and time to quantify the impact of infill wells on current producers. It can also analyze the impact of completing wells on a pad.

“The timing does matter,” he said. “By using data we’ve already captured, we’re able to synthesize a way to quantify that impact and build those new processes into the analysis.”

Finally, Ayata has created a way to isolate the decisions an operator makes while completing a well and their impact on ultimate production.

The other speaker on the panel was Toby Deen with Devon Energy Corp. (NYSE: DVN). Deen said that Devon is a relatively recent entrant to the Eagle Ford, entering the play with its acquisition of Geocenter Energy in late 2013.

“The afternoon we closed on the deal, our CEO sent our team an email wanting to know what our choke management strategy was,” Deen said. “At the time I couldn’t even find the field on a map.”

The CEO asked the right question, as it turns out. Many companies choke back their wells, fearing that full-on production will damage the well. Deen’s team set out to find the truth.

While different operators go about things different ways, the team determined that some practices were fairly standard across the board. Operators scheduled choke bumps, had target IP rates and built drawdown type curves. Sometimes operational constraints were a factor. But the most consistent trend was a predetermined procedure applied to every well.

In other words, reservoir heterogeneity was not factored in. “We had quite a dynamic field geology-wise and reservoir-wise,” he said. “From lease to lease we have different GOR windows and a lot of heterogeneity. You couple changes in reservoir thickness and permeability, and then you have the perpetual cycle of continuous improvement with completion designs, and you start wondering how proppant loading or fluid systems are going to impact well performance. How does our drawdown strategy maximize that? It really steers the discussion.”

The team went back to basics, determining that the goal was to maximize economic returns without damaging the well. The result was an engineered drawdown strategy specific for each well. The team relies on high-frequency data collection and real-time technical analysis. This enables the team to spot problems while not limiting flowback.

The results speak for themselves. Using the engineered strategy improved production at least 100% in both 30-day and 90-day cumulative oil production.

Deen concluded that delayed production actually adds risk to EUR and that this strategy provides competitive advantage. It is now being applied on other Devon assets as well.

Rhonda Duey can be reached at