• Roughly half of the onshore well stimulation fleet is stacked.
  • Well stimulation pricing has bottomed.
  • Operators pursue ‘tried and true’ completion recipes and forego experimentation in tough price environment.

It’s the new theory of relativity. But instead of physics, this theory applies to well stimulation, where service providers are reporting a stable market—stable, in this instance, meaning relatively unchanged at low levels of activity.

Well stimulation service providers tell Hart Energy that pricing finally has hit bottom. Some providers are operating below cash cost, while all well stimulation firms are working below replacement cost. Pricing per stage ranges from the mid-$30,000s in parts of the Midcontinent up to the mid-$50,000s in select markets elsewhere. In general, pricing is below $50,000 on a per-stage basis vs. the mid-$80,000 range at the beginning of the year.

Well stimulation pricing moved down in two steps. The first was a reduction in charges for pressure pumping services, which characterized first-half 2015. The second step involved operators separating out bundled services and extracting concessions directly from vendors. Operators have become adept at negotiating price breaks for bulk commodity proppant and chemicals that were once provided through well stimulation firms. At this point, operators have successfully squeezed all the blood from the well stimulation turnip.

Hart Energy’s market intelligence surveys indicate that roughly half of the industry pressure pumping capacity has been stacked. For the remaining units, variously estimated between 7 million and 9 million in hydraulic horsepower in aggregate, service providers report utilization in the low 60-percentile range.

Meanwhile, operators have settled on “tried and true” completion techniques. Few are open to experimenting in the current low-price environment. That means a completion recipe that generally entails slick water, plug and perf (PNP) and large proppant loading, often in excess of 200,000 lbs per stage. Those techniques are applied to longer wellbores, which exhibit more stages more closely packed together and feature anywhere from three to five perforation clusters per stage. Average stage spacing, based on survey reports, is about 68 m (225 ft) across the domestic horizontal market compared to 91 m (300 ft) a year ago and 152 m (500 ft) in dry gas plays four years ago.

Coiled tubing-conveyed fracture stimulation involving high stage counts and cemented sleeves has established a beachhead in the market. On a per stage basis, the cost is lower than standard PNP. However, the larger number of stages per well, in some cases nearing 60, means overall well cost is higher. Operators in some markets also are experimenting with dissolvable plugs.

The evolution in the downhole completion recipe indicates a subtle shift in industry philosophy. Originally, operators sought to bore the lateral as quickly as possible, then execute a massive frack to access the best rock. Reach was important. Now operators are intent on landing the lateral in the very best reservoir rock to start, even if it adds a day or two to drilling, and increasing the density of fracture initiation points closer to the wellbore. It’s about quality, if quality is defined as complexity in near-wellbore fractures. The new completion technique is boosting initial potentials, whether measured over 30 days, 60 days or 90 days, and may well be increasing EUR as incremental gains in recovery factor are coming to tight oil just as they did to shale gas a decade ago.

How fast can the sector respond if demand returns? Well stimulation providers tell Hart Energy that the main bottleneck will be people. Thousands have been let go, many with experience, and inexperience on a pump job makes everyone nervous. The time to train and deploy new crews could stretch six months to a year after demand returns, although stimulation pricing will have started moving higher well before then.

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