Other than the Biblical tranche of drought-busting rain that characterized second-quarter 2016, it’s been too quiet for far too long in Eagle Ford Country.
The Eagle Ford and its world-class reservoir rock has been beset by the same economic challenges as other unconventional markets. Rig count, according to Baker Hughes Inc., fell below 30 active units drilling horizontally in second-quarter 2016. About one-third of rig activity is confined to Karnes County, Texas, in the core Eagle Ford. With drilling activity down 85% vs. the 2014 peak, the Eagle Ford ranks second among the hardest hit domestic markets.
It leads the market in production declines, with oil down about 250,000 bbl/d in June 2016, or 19% from peak.
Although commodity pricing improved, it still had not reached the levels necessary to improve activity. Hart Energy’s Heard in the Field surveys suggest operators will look at completing the backlog of drilled but uncompleted wells (DUCs)—an estimated 800 to 900 wells—at $50 oil. Indeed, the percentage of batch-completed wells moved up to 10% in 90 days to 48% of wells in June 2016, suggesting operators were tackling the DUC backlog. But it is going to take oil at $55 or higher to stimulate demand for oil services. That price threshold increased 10% over the first six months of 2016 among survey participants.
But there are signs the bottom is at hand, which is the first step in recovery. There was news about progress in the Austin Chalk as operators such as Blackbrush Oil & Gas LP successfully applied unconventional techniques to a tight carbonate formation and then sold its Eagle Ford area assets to longtime Austin Chalk player EnerVest Ltd. There was the intriguing EOG Resources Inc. announcement about applying EOR via natural gas injection in the Eagle Ford oil window. EOG claims a 30% to 70% recovery uplift on a $1 million investment for wells two to five years old.
For land drillers, rig rates established a floor of $15,000 per day for the benchmark 1,500-hp Tier I AC-VFD unit, down from $17,500 at year-end 2015. Workover contractors had been especially hard-hit, though pricing was stabilizing at $280 per hour for a 500 Series C unit, down from $358 per hour at year-end 2015. Workover contractors saw job mix for routine maintenance increase from 56% at year-end 2015 to 77% in June 2016 as operators did only what was necessary to keep wells flowing.
Stabilization also settled on the well stimulation sector. Like other land markets, the Eagle Ford has seen pressure pumping capacity move to regional centers elsewhere. In Texas, it meant relocating equipment and crews to the Permian Basin and servicing regional markets out of a West Texas base. The installed base of more than 1 million hydraulic horsepower (hhp) that characterized the Eagle Ford in 2015 shrank to 281,000 hhp in June 2016, while area crew count dropped from about 35 in late 2015 to 13 in June 2016.
The average price per stage followed suit but seems to have bottomed in the low to mid-$30,000 range, depending on lateral length and proppant volume. As in other domestic markets, slick water, plug and perf, and bulk commodity sand at 1,500 lb to 2,000 lb per lateral foot is now the standard completion recipe.
Well costs appear to have dropped below $6 million, although 30-day IP rates have plateaued in the 700 boe/d to 800 boe/d range despite operators high-grading wells. As floodwaters recede, the region, and the oil and gas industry, anticipate sunnier days ahead.
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