HOUSTON—Considering today’s lower commodity prices, despite recent gains, not too many oil and gas companies are pursuing refracturing opportunities in shale plays.

But the potential for economic and production uplifts await, according to a panel of experts.

That is if the well is a suitable candidate and effective solutions are carried out.

Speaking on April 21 during Hart Energy’s Refracturing: Cracking the Code breakfast seminar, experts from Baker Hughes, Weatherford, Fracknowledge and Eventure Global Technology agreed that refracturing has benefits. Potential also exists to learn more about which methods work best for certain reservoir conditions by testing concepts on some of the 8,000 or so drilled but uncompleted wells (DUCs) across North America.

However, low commodity prices have put refracturing programs in the Haynesville and Barnett on hold.

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“We’re in a pricing environment where there is yet one more round of layoffs. Who’s going to go take risks like that?” asked Tim Leshchyshyn, president of Fracknowledge. “But if you actually look at the statistics, it’s amazing.”

Refracs account for less than 25% of the original drilling and completion costs, according to Leshchyshyn. Given oil is about half of what the industry wants it to be to thrive, there is inherently a 100% return on investment—with a quarter of the cost at one half of the return, he added. But, “The return on investment is sometimes 400%. This is above the incremental reserves. This is above net present values.”

The talk about refracturing opportunities and challenges came as companies continued to seek cost-efficiencies during a downturn brought on by a supply-demand imbalance. Refracturing instead of drilling could be among the options, considering costs associated with refracturing a well are about $1 million compared to between $6 million or $7 million to drill a new well.

What’s New? What Works?

Harsh Chowdhary, engineering manager for Eventure Global Technology, referred to a 2009 refrac job involving three wells from the same pad. Two wells used a chemical diverter and one used expandable lining. “When the refrac was done, the mechanical isolation well showed 40% higher production rates than the chemical diverter,” he said. “It is more costly than the other options, but I think experimentation and R&D is going to drive the technology.”

Leshchyshyn called the economics of refracturing outstanding and added that refracturing is more successful than it is not. But “it’s unknown and a little uncomfortable for us,” especially in this low-price environment.

While the industry has refractured vertical wells in the last three decades or so, refracturing of horizontal wells is in the early stages, said HC Freitag, vice president of integrated technology for Baker Hughes Inc. (NYSE: BHI). The process typically used chemical diverters to access certain zones, he said. These have evolved to include degradable diverters.

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However, more diagnosis is needed when determining where to refracture.

When the method takes a “Hail Mary, or pump and pray” approach, the results have been disappointing, Freitag said. Diagnostics are essential. Once unproduced hydrocarbons have been found, the targeted zone can be stimulated, he said. Currently, there is work within the industry using straddle tools to properly stimulate or restimulate zones that were previously bypassed.

“A lot of this technology is being used as we speak,” he added. “The marriage of science and research and engineering to the pressure pumping schedules are going to make this happen. It’s still in its infancy. I think there is still a lot of work to happen before the second wave of the unconventionals.”

Candidates, Challenges

Rapid decline rates or wells that never produced properly could be refrac candidates.

For Rob Fulks, director of completions optimization for Weatherford, candidate selection involves using a grid with stars and cash cows, for example, looking at reservoir, completion and wellbore qualities along with production history. The candidates will fall to one area of the grid. Then, further data analysis is done. However, all candidates aren’t necessarily chosen. “You go after the wells that have the lowest risks,” he said.

As for the methods, diversion, chemical isolation and straddling all work, he said earlier in the program.

But some methods work better in some basins, while only one option is suitable for others.

“If you have a cemented liner system, which is predominate in the United States, mechanical isolations are a lot better method,” Leshchyshyn said. “In some basins where you have an open-hole packer system behind the liner, those systems can be mechanically isolated but past those perfs … you are left with possibly diverters.

“What if you want to double the number of stages? How do you do that behind the liner? You might not have mechanical methods; however, some people are experimenting with cementing all of those systems in and then you can do a normal, solid diversion system mechanically, but then you’ve left with chemical diverters. How does a chemical diverter bridge off in a perfed situation much easier than it is an open-hole frac?”

How will the area be plugged before breaking into another area? There are some challenges, he said.

Regardless, upfront engineering work and staying the course on executing options are needed for a successful refrac program, Freitag said, noting operators are still experimenting with different types of diverters, planning, straddling and more elegant systems.

With about 8,000 DUCs and tens of thousands of wells that may have been under-stimulated initially, there are enough test candidates and distributed risk among operators to learn more about refracturing, he said.

“This is where the industry I think has to rally,” and look at what it should be doing to keep the unconventional industry going in the U.S., Freitag added.

Velda Addison can be reached at vaddison@hartenergy.com.