oil production statistics

There was a surge in one number in September’s oil production report that particularly surprised North Dakota Department of Mineral Resources Director Lynn Helms.

It wasn’t the crude oil production numbers, which were down for the month 2.5 percent or 37,000 barrels per day.

And it wasn’t the gas production numbers either, which were down a similar amount, 2.2 percent or 67 million MCF per day.

Helms had earlier predicted these would be down around 7.5 percent at the Western Dakota Energy Conference.

Flaring also dropped slightly by 58,023 MCF per day, to 518,317 MCF per day. That put September’s flaring at a little more than 18 percent. The capture rate was meanwhile reported as 83 percent, which is still 5 percent below the state’s target.

Those numbers were all in line with what Helms had been expecting.

The number that did surprise Helms was a surge in inactive well counts, which rose by 400 during the month of September.

Helms said he wasn’t sure what caused that, though there are potentially multiple causes. One may have been closed roads, which could have interfered with transporting produced water to saltwater wells.

Workover rigs also can’t move when roads are closed. They are among the heaviest equipment in the Bakken. These keep wells repaired and running.

“We have been getting some indication from our operators that marginal wells are struggling to make a profit at these oil prices, so it is entirely possible that as we approach winter, people are shutting in or inactivating marginal wells,” Helms said. “Especially as winter approaches with the wet weather and snow in October. I think October will tell us a lot about that.”

There’s also been a growing trend lately to move away from gathering sour natural gas, which contains hydrogen sulfide.

“In fact we have some cases coming up on the docket as a result of that,” Helms explained. “That would result in conventional wells being shut in, until that can be resolved either through Industrial Commission relief to allow that gas to be flared or some type of well site processing. So there are several factors at play here.”

Helms said he would be watching the inactive well count carefully, and has already begun having some conversations with operators about it.

“Inactive turns into abandoned which turns into orphaned wells,” Helms said. “It’s like the canary in the coal mine, so to speak, about what could potentially end up being a large liability for companies. Once a well has been inactive a year and goes into abandoned status, it is difficult to transfer to a new operator and put back in production, so it can become a liability.”

As far as other numbers that Helms tracks, permitting has continued at a normal pace. It is slowing a little as the holidays and winter freeze approaches.

Well completions have remained above revenue forecasts, Helms said, while gas gathering and processing projects appear to be on schedule for December or January, according to conversations he’s had with those companies. The plants are needed to relieve constrained capacity that has been strangling new production.

Midstream companies, meanwhile, have not had the same difficulty gaining access to capital that exploration companies are experiencing, Helms added.

“What we have seen with capital is that a lot of private capital funding for midstream infrastructure is over-funded,” Helms said. “I was at a conference in Wisconsin mid-year and the venture capital people there indicated there was more capital looking for a place to invest in gas gathering and capture and petrochemical than there was a home for.”

Drilling a well comes with risks that the well won’t produce as expected, or that prices may drop and return on investment will be much less than planned. Midstream volumes tend to grow over time, Helms pointed out, and are more of a known future quantity.

“The capital hasn’t entirely gone away,” Helms said. “But it has shifted the industry sector it wants to be invested in.”

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