Small US onshore oil wells that produce as little as 10 b/d of output face the prospect of shut-ins from the current crude price drop, but any large-scale closures are still unlikely, consultancy Rystad Energy said today.
These low-volume wells, commonly known as stripper wells, account for about 1.2mn b/d, or a little over 10pc, of total US onshore output of about 10.5mn b/d last year.
At $20/bl WTI about 75pc of these marginal stripper wells are still able to cover their cash cost, according to Rystad, but the remaining 25pc, or about 300,000 b/d, are not. Given their size and output, these wells will be the first candidates for shut-in. If crude prices fall further, more will face closures as they are not able to cover their costs. Nymex WTI settled at $20.09/bl yesterday, at its lowest since February 2002.
Even so, shutting down the vast majority of these stripper wells is unlikely because the cost of permanently closing them would be higher than the losses the owners would incur in keeping them in production for a few years.
The cost to close ranges anywhere between $20,000-$40,000/well. Even if oil prices are $10/bl below the cash breakeven, a typical marginal well will lose around $600/month, or $7,200/year. Hence, the operator can keep these wells producing for about four years before the loss would match the cost of abandoning the well.
Rystad's analysis shows that historically most shut-ins of these wells have been for good, and they have rarely been reactivated when oil prices have recovered because of the high cost of restarting them and the loss of reservoir pressure that would occur with the closures.
More than half of marginal wells are operated by private operators, including private equity-backed players and hundreds of small independent producers and family-owned businesses, it said. But about 40pc of the output is controlled by publicly-traded independent operators, with nearly 340,000 b/d, and majors accounting for 160,000 b/d.
"Hence, stripper well supply may be less elastic and flexible than some people might think, and it might not be the source of supply that would help balance the market," Rystad's head of shale research Artem Abramov said.
More than 440,000 b/d of Permian oil, in Texas and New Mexico, presently comes from marginal wells, it said.
US energy investment bank Tudor Pickering Holt in a note today said while most public upstream operators have yet to detail their shut-in plans, a potential closure of a portion of their production looks imminent as storage fills up in coming months.
