Denver — While increasing the use of proppant during completions has been all the rage among producers over the past several years, at least one CEO said his company has managed to save on completion costs by lowering the amount of proppant but still maintaining similar initial production rates.
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"New diversion techniques are allowing us to complete better performing wells while using about 30% less proppant, reducing capex by approximately $400,000 per well," said Whiting Petroleum CEO Brad Holly, during a presentation at EnerCom in Denver on Monday morning.
Whiting is one of the largest producers in North Dakota's Bakken Shale where it holds more than 400,000 acres. In the company's Hidden Bench play, located in the core of the Bakken in McKenzie County, it has been able to reduce proppant by about 50% and still maintain similar rates of production. It discovered that it could achieve the same production levels on new wells using 7.3 million pounds of sand as it did with 15.2 million pounds.
"We use a lot of entry points and less sand," Holly said. "We optimize completions for each well. Going bigger is not always better. It is about optimizing completions."
Despite Whiting's new approach to reduce the amount of proppant per well, most producers across the board utilize much higher volumes of frac sand than they did just a few years ago.
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"In the early days, the frac was just a small part of the well completion," said Chris Wright CEO of Liberty Oilfield Service, a company focused solely on hydraulic fracturing. "Now, it is the single largest piece of well completion. The amount of sand pumped across the industry is up more than two-and-a-half times what it was in 2014. Liberty pumped about 20 times as much sand last quarter as we did back in 2014."
Liberty currently runs 22 frac crews spread across the Williston, Powder River, Denver-Julesburg, Permian and the Eagle Ford. It plans to deploy two more frac fleets during the first quarter of 2019.
Whiting, meanwhile, has lowered costs on its Bakken wells by reducing the amount of proppant as well as decreasing the amount of drilling and completion time per well. Since 2014 the company has lowered average drilling time per well from 15.5 days to 8.9 during the second quarter of 2018. Improved completion efficiencies and lower drilling costs have reduced D&C costs from $9.1 million per well in 2014 to an average of $6.75 million in 2018.
Another facet to making drilling more profitable in the Bakken is the improved differentials to WTI the play has enjoyed lately. Bakken differentials have improved from minus $10.93 in 2014 to minus $3.91.
Last month was the first time the Permian lost its top rank as the most profitable basin in the US, according to S&P Global Platts Analytics. And this month the trend is even more pronounced, as the Permian continues to suffer from lack of takeaway capacity and ever-widening crude price differentials. In July, the Bakken edged out the Permian as the most profitable basin in the US. Not only did the Bakken hold on to the top spot this month, but the Permian has also been outperformed in terms of returns by the Eagle Ford and the STACK. In August, the internal rates of return per well for the Permian dropped by about eight percentage points, down to 42%, causing the basin to drop to fourth place in profitability behind the Bakken's 49%, the Eagle Ford's 46% and the STACK's 43%.
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