• Modest signs of recovery appear in Eagle Ford well stimulation.
  • Lower cost Permian Basin draws capital away from South Texas.
  • Operators experiment with hybrid gel completions.

Houston, the Eagle Ford has landed. Unfortunately, the play is not yet ready to soar. South Texas was among the hardest hit markets in the downturn, with drilling levels down more than 85% from peak. Indeed, rig count actually dropped again early in fourth-quarter 2016 but edged back into the mid-30-unit range as the industry heads into the holiday season.

South Texas has seen oxygen sucked out of the Eagle Ford as operators reallocate capital to the lower cost Permian Basin. Service providers are following demand with regional well stimulation fleet count moving up or down monthly as equipment and crews continually rotate between the Permian Basin and the Eagle Ford.

The regional pressure pumping fleet fell by one to 22 in mid-November, with 525,000 in hydraulic horsepower active in the play. Price per stage rose on the basis of more proppant and an increase in average lateral length coupled with a modest reduction in spacing between stages to an average 65 m (214 ft).

Slickwater plug and perf with 400,000 lb to 500,000 lb of sand per lateral constitute the standard Eagle Ford completion recipe. Operators are experimenting with a closing slug of crosslink gel and coarser regional 30/50 sand at the end of each stage to improve conductivity, which also boosted the price per stage.

Operators are now routinely completing wells as drilled, although the percentage of zipper fractures has not changed over the last 90 days, with solo fractures representing 57% of job mix, down modestly from 59% this summer. Operators have been drilling Eagle Ford wells at a pace of 80 wells per month in fourth-quarter 2016, up from a low of 66 when the market bottomed in June, according to the U.S. Energy Information Administration. Operators are mostly completing wells when drilled instead of banking locations into the drilled but uncompleted (DUC) category. Well completions ranged between 110 and 120 monthly through third-quarter 2016 as some operators reduced DUC inventory.

Drilling contractors are reporting more phone calls and some tire kicking as operators investigate the availability of Tier I pad-optimal drilling rigs. So far, those inquiries have not materialized into additional work, and rig providers do not expect any significant increase in activity through first-quarter 2017.

Drilling contractors report 34% utilization, with two-thirds of the regional rig fleet stacked. Rig rates for the benchmark Tier I 1,500-hp AC-VFD unit averaged $15,300 per day, virtually unchanged since third-quarter 2016. A few rigs are on legacy term contracts, some of which are slated to expire in the next 180 days. Otherwise, work is well-to-well, with spot market daily pricing ranging between $14,500 and $18,000 for the most desirable pad-capable rigs.

Workover contractors also report 35% utilization. Recent restructuring among national-level workover providers who market fleets in the Eagle Ford underscore the challenges facing the sector. Prepackaged restructurings keep companies viable but don’t change the competitive landscape since equipment and crews are not removed from the market. Increased utilization at below breakeven pricing will not help workover companies improve viability.

Contractors report skilled labor is now in short supply after many workers left the industry for construction jobs or work in the Gulf Coast refinery complex.

Meanwhile, operators remain wary of committing to new work because of commodity price volatility. Well stimulation contractors indicate customers need $54 oil and $3.50 gas to expand completion programs, while hard-hit drilling contractors indicate customers won’t significantly expand drilling activity until oil prices are closer to $60, a price well above the industry’s 2017 expectations

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