As oil and gas operators move toward bringing previously shut-in wells online, if such moves haven’t been done already, industry experts seem to agree there will be no significant impact on unconventional shale reservoirs for the most part.

W.D. Von Gonten & Co., a Houston-based petroleum engineering, geological services and petrophysical modeling firm, has conducted several tests on shut-in wells and bringing them back on different rates.

“We’ve seen no reservoir damage to speak of that would affect the production data,” Bill Von Gonten, the company’s president, said last week during a Tudor, Pickering, Holt & Co. conference session on reservoirs. “Actually, what we’ve started to see is positive. The pressures are built up. In some wells rates have doubled from what they were shut in at, and then the water has gone down. In another month we probably won’t be talking about the damage. It’ll be what happened; how can we explain the production that we saw from the wells.”

Companies shut in uneconomic wells as oil prices cratered due to falling demand resulting from the global coronavirus pandemic and a short-lived price war between Saudi Arabia and Russia. The situation remains in flux as eased stay-at-home restrictions give way to more COVID-19 cases.

Unwilling to sell resources at low prices, U.S. producers were expected to curtail about 1.75 MMbbl/d of existing production by early June amid operating cash losses, inadequate storage capacity and demand loss, according to IHS Markit. Most of the curtailed volumes were anticipated to return in the summer and fall 2020 if market conditions improved with WTI above $30/bbl and storage available.

Industrywide, everything seems to work from a price perspective in the U.S., according to Dave Pursell, executive vice president of development planning, reserves and fundamentals for Apache Corp.

Houston-based Apache operates about 12,000 wellbores in the Permian Basin, mostly in the Wolfcamp and Bone Spring formations. The rest are legacy vertical assets in the Central Basin Platform.

“At $40, our DUCs (drilled but uncompleted wells) will compete in our portfolio again, though they might be economic at a lower price,” Pursell said. “They can compete with our international alternatives at $40 and then a full-on drilling program in the Permian starts to compete at $50. That doesn’t mean at $40 we’ll initially complete the DUCs or at $50 we’ll bring a program on. But we can start having that conversation.”

The company shut in about 2,500 wells in the basin and elected not to fix some wells with mechanical problems because of low commodity prices. Apache’s workover count dropped from 60 rigs to 12, including two doing standard plug and abandonment work.

Shutting in wells is nothing new. Operators have taken such steps for various reasons before and brought production back online.

However, a sliver of production might be permanently lost from shut-ins, panelists agreed. These include wells with high water cuts, bringing corrosion potential, Pursell said.

“We tried to get the wells shut in in a proper state so that we minimize any return to production issues,” he said.

He compared the scenario to not cranking up a vehicle.

“If you leave it in the driveway for a week, you’re OK,” he said. “You leave it in the driveway for three months, you’re likely going have a hard time getting started.”

Industry wells likely to lose production are expected to be older ones already near the end of their life, according to Pursell. He noted the number of wells in this category might be large but their total production is not significant.

Some wells might encounter artificial lift issues, with electric submersible pumps (ESPs) damaged by corrosion and paraffin the longer a well sits idle.

The extent of potential problems when bringing a well back online comes to down how the well was preserved at the beginning of the shut in and geology, added Gary Olliff, executive chairman of Brigade Energy Services LLC.

“There’s always some risk that the well may not return to normal production levels,” he said.

Returning production also carries a price tag.

Removing fluid from the wellbore and running tubing could start around $15,000, while tasks such as replacing pumps and tubing due to paraffin buildup could cost at least $25,000. Costs move further up when ESPs need fixing. Such repairs run between $150,000 and $175,000, Olliff said, noting replacing one is upwards of $300,000.

Gas lifts may have fewer problems, compared to rod pumps and ESPs, considering most of its complicated parts are at the surface, Pursell added, making way for regular maintenance with the well shut in.

“What we’re starting to see and have been doing for some time are the clean out jobs, going into these horizontal wellbores and going all the way to the toe and cleaning them out,” Olliff said. “Those can be upwards of $150,000 all in, depending on if there’s any treatments done. Water treatments with diversion agents [are] anywhere from probably $35,000 to $50,000. Worst case scenario is refrac, and those things can cost upwards of $2-$3 million.”

Also, of concern are wells with high H2S and CO2.

“Those kind of well reactivations, depending on how long it’s been shut down, can easily result in some parted tubing rods and things like that,” Olliff said. “Again, it goes back to the geology and if they were preserved properly.”

The latest downturn also presents another learning opportunity for shale players, particularly when it comes to collecting data. Under this price environment, the industry is not going to get the core and physical logs it always seeks, Von Gonten said. Performance data during production has been obtained. Now is the time to collect shut-in data, matching drawdowns, rates of pressure and build-up data.

Panelists also discussed the learning curve associated with cube developments in the Permian Basin as well as relative permeability and low recovery rate concerns among other topics.

“There’s something else down there that we’re missing,” Von Gonten added, pointing to relative perm problems and water challenges. “I think there’s going to be a lot of lessons learned from the build-up data after the wells have been shut in.”

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