As a result of a nearly 12% drop in global oil demand compared to last year, North American shale producers have been forced to cut production and new wells. According to Rystad Energy, U.S. oil production will fall to 10.7 MMbbl/d in June, a two-year low. U.S. producers have significantly cut back on drilling new wells and shut in producing wells to slash expenses and level off the massive oil glut that has depressed prices.

However, shutting in wells presents operators with a new set of challenges, with key decisions looming over which wells to shut in, how long can they be shut in without significantly impacting their long-term production and how taking wells offline affects the reservoir.

A panel of industry experts discussed these issues during an SPE-sponsored webinar on May 21 that addressed unconventional well shut-ins and their long-term implications.

Eric Gagen, president of EPG Solutions Co., explained that although operators might initially be inclined to shut in their poorer-producing wells, it could be more beneficial in the long-term to choke off higher-performing wells.

“In an ideal world, with no financial pressures, you’d be probably want to choke back or close in your very best wells first,” Gagen said. “That may sound counterintuitive, but it actually makes a lot of sense when you realize those wells are the best wells because they have lots of hydrocarbon saturation, they’ve got lots of pressure and they’re very difficult wells to damage. When you turn them off, they turn back on.”

Gagen acknowledged, however, that a company’s financial obligations might not allow it to close off their best performers.

“Everybody has financial obligations,” he said. “As an operator, you’ve got to have cash flow coming in to pay those financial obligations. So, there is going to be tremendous pressure to close in the worst wells and keep the best wells on.”

The problem with closing in lesser-performing wells first is the varying dynamics of the well—its potentially poor rock quality, its poor hydrocarbon saturation or insufficient bottomhole pressure—are likely to make those wells more difficult to bring back onto production, Gagen said.

“There are also two other factors—one is leaseholder obligations. By closing in wells you may have financial penalties that could be worse than the consequences of leaving the well producing at a small loss,” he said. “The final one is flowlines and tank batteries. If you can close in a whole area that flows into a certain area, then you can idle that particular infrastructure. It sounds like a huge cost savings, but if you’re in an area like North Dakota where crude lines can gel up or even freeze up in the wintertime, it might be something you try to avoid.”

Another key consideration that panelists addressed regarding shutting in wells and bringing them back online is water management. Shut-in wells, whether they are high performers or low-performing wells, are likely to bring back higher volumes of water, perhaps nearly as much as during the initial frac job, and those dynamics and costs should be accounted for when considering a shut-in program.

Buddy Woodroof, technical manager at ProTechnics/Core Laboratories, said some cash-poor independent operators might be inclined to shut down high-volume wells to avoid water disposal costs. However, he said other factors that impact the reservoir should also be considered.

“Let’s think about how much water these wells are producing,” Woodroof said. “If they are high water producers, there may be a problem with water block issues when you start to bring the well back on. But some have said it’s not just the water volume that is produced, you should also consider the oil-water ratio. That could be a critical determinant as to what’s a good candidate (to shut in) and what’s not.”

Gagen explained that as shut-in wells pressure up, once put back online they could produce more water than a wellsite’s infrastructure is designed to handle.

“All of these wells are going to pressure up to some degree,” he said. “And some of them are going to produce a lot of water initially. And while the flowback facilities and tank batteries for these wells may be properly sized for their expected flowing rates for oil and gas, they may not be properly sized for really large batches of load water. So, you may see a situation where you’ve actually got to get flowback crew back out there to start getting the load water out of these wells. It probably won’t be as much (water) as an initial frac job, but it could be a considerable amount.”

Woodroof added that wells with undulated wellbores might not serve as good candidates for shut-ins nor would those utilizing electric submersible pumps (ESP).

“Those are not good candidates, because those ESP pumps are pretty touchy,” he said. “So, I would look for rod pump wells as leading candidates.”

While some panelists advocated for shutting in newer wells, Lyle Lehman, principal consultant for Frac Diagnostics LLC, suggested it might be more prudent to consider older inventory for shut-ins because of the differences in completion designs and proppant pumped downhole during the frac stages.

“I would choose an older well perhaps with the reservoir pressure reduced low to depletion over a newer well with lower quality proppants for shut-ins merely for the reason that I can clean up a moderately conductive fracture more inexpensively and effectively than a case where the proppant has potentially crushed on the initial production flowback or actually becomes part of the reservoir due to crushing or damage from crossflow,” he said.

Most analysts are predicting that any kind of large-scale oil recovery will not likely occur until 2021 at the earliest, as the world struggles to emerge from the COVID-19 pandemic and energy-intensive industries like transportation take small steps toward their previous consumption demands.

But if oil prices remain in the $30/bbl range, some, like Rystad, believe production could climb to about 11 MMbbl/d.

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