North Dakota made headlines recently with its crude oil production numbers for May, which surprised many and left some scratching their heads. Brian Scheid looks into what drove the production, and what it means for future production, in this week’s Oilgram News column, At the Wellhead.
For months, conventional wisdom held that persistently low crude oil prices would be countered by a slowdown in US shale oil production, but to the dismay of many hoping for a return to the days of $100/b, US oil production continues to rally in spite of falling and stagnant prices.
Earlier this month, the US Energy Information Administration forecast US production to average 9.47 million b/d this year, which would be the most crude produced domestically in 45 years. The forecast was up 750,000 b/d from the 2014 average and up 40,000 b/d from EIA’s 2015 production estimate announced a month earlier.
Arguably, this trend is best seen in North Dakota.
Amid persistently low oil prices and a plunging rig count, analysts and state officials were somewhat shocked when North Dakota’s Department of Mineral Resources revealed last week that crude production grew roughly 3% from April to May, falling just shy of the all-time supply record.
“I was surprised,” Lynn Helms, the agency’s director and North Dakota’s top oil official, told reporters. “I expected May to be a down month.”
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Aided by improved drilling technology and increased efficiencies, May oil production reversed a recent downtrend that followed December’s all-time high of 1.23 million b/d.
Helms said he expects statewide production to at least hold steady throughout the year and, potentially, jump by another 30,000 b/d by the end of the year as operators scramble to drill uncompleted wells before leases expire and possible penalties are levied.
But monthly production could exceed these expectations and may continue to break new supply records due largely to rig efficiency efforts which have seemingly disconnected the relationship between rig counts and production. As state data shows, as the rig count falls, production continues to climb, making it entirely possible that a new production record could come with rig counts at levels not seen since before the Bakken oil boom began.
“The strategy appears to be, as long as we’re stuck in this $55/b to $60/b oil range, to just sustain production and sustain cash flow with as few rigs as possible and fracking [uncompleted wells],” Helms said.
The average rig count fell to 83 in May, a dramatic drop from May 2012 when the rig count averaged 211. But those 83 rigs produced nearly twice as much oil as the 211 rigs throughout May 2012.
Taken broadly, each rig averaged 14,472 b/d this May, up from 5,500 b/d per rig in May 2014, 4,338 b/d in May 2013, 3,030 b/d in May 2012, 2,065 b/d in May 2011 and 2,600 in May 2010, according to a Platts analysis.
Recent production levels could have been even higher if not for state conditioning rules which went into effect earlier this year. The new rules, which require Bakken crude to have an RVP of 13.7 psi or below before it is shipped by rail, has resulted in a 1% to 2% drop in oil volume as volatile liquids have been burned off and wind up in gas gathering systems, Helms said.
Helms said that producers are finding that efficiency gains are countering sweeping cut-backs in drilling. Just two years ago, it took operators about 6 weeks to drill a single well. It now takes less than four weeks to drill two wells.
“We have seen rig efficiency double since 2013,” Helms said, pointing out that each rig can now get 24 new wells in just a year.
Additionally, operators have concentrated their drilling efforts in only the most prolific, core areas of the Bakken, resulting in dramatic increases in initial production rates. For example, in May 2014, two dozen wells initially produced 500 b/d. In May 2015 there were no wells that had an initial production rate of less than 500 b/d, and three wells had initial production rates of over 3,000 b/d. No wells had rates above 3,000 b/d a year ago.
Helms said this trend is certainly aided by reductions in drilling costs, which have fallen by about $1 million per well.
Ultimately, Helms said, production could increase even more if prices rebound. This would likely be at $65/b for WTI when fracking crews will start to return to many rigs and $70/b for WTI when drilling rigs “go back to work in a more significant way.”
Due to all the recent gains in rig efficiency and production rates, that new “magic price point” might be $60/b for WTI, Helms said.
EIA still forecasts production to peak in 2015 and begin a gradual decline in 2016. But Bakken supply would likely remain at or above record highs even if there isn’t much change in prices, Helms said.
“We’re capable of sustaining production for a couple of years.” — Brian Scheid