Re-vitalization is underway in the greater Rockies oil field services market outside the mighty Bakken Shale.

Six months ago, pressure pumping equipment was rotating out of the dry gas Rockies for better markets elsewhere, but that trend appears to be reversing, according to Hart Energy market intelligence telephone surveys. There are two primary reasons for this. The first is expanding activity in the Niobrara Shale, not just in the D-J Basin, but across the Rockies. Secondly, Piceance Basin dry gas has given way to a condensate-rich play.

Rising activity in both cases hasn’t been enough to attract capacity back to the region—yet— but it has increased utilization of existing equipment.

“We saw fleets move to other plays when the Piceance slowed, but there has still been adequate horsepower in the region,” one top tier service provider told Hart Energy researchers during the latest round of market intelligence telephone surveys. “New activity could have the major providers looking to add to their fleets.” The market intelligence surveys were conducted at the end of July 2014.

Service providers peg regional hydraulic horsepower (HHP) at 1.5 million HHP.

“I know there seems to be plenty of equipment in the region, probably about 1 million HHP,” a mid-tier service provider told Hart Energy via a telephone interview. “If activity continues to ramp there will be several of us looking to move fleets back to the region.”

Service providers pegged average per stage costs on Niobrara wells at $105,000. Horizontals are averaging 19 to 20 stages spaced from 200 to 325 feet apart across 5,000 or 6,000 feet laterals, according to service providers participating in the Hart Energy market intelligence telephone survey.

Operators continue drilling vertical tests to delineate the Niobrara but soon plan to begin drilling horizontally. Meanwhile operators are experimenting with a variety of completion techniques ranging from slick water and sliding sleeves to cross linked gels and plug and perf as they hone in on the best methodology.

Slickwater is more common in the deep Niobrara whereas operators active in shallower Niobrara plays are occasionally using nitrogen foam and CO2 fracs. The enhanced fracture stimulation method that employs massive inputs of sand as proppant in areas like the Eagle Ford has yet to take hold in the Niobrara where the volume of sand per stage is still relatively low.

Operators are using cemented liners in some cases and experimenting with the placement of perforation clusters as they seek to solve the Niobrara engineering challenge. In fact about half of survey respondents cited the use of plug and perf only with the other half reporting a hybrid completion involving a combination of sliding sleeves and plug and perf methodologies.

Of note, rising demand has service providers anticipating an opportunity to increase pricing going forward.

Separate surveys of land drillers in the region indicate demand for drilling rigs is rising incrementally in the Niobrara and DJ Basin and is flat—but steady—elsewhere. Newbuild rigs are starting to show in the DJ Basin and land drilling contractors anticipate more will arrive by early 2015. Similar to markets elsewhere, rig rates for newbuild equipment range between $26,000 and $28,000 per day, depending on configuration for a 1,500 horsepower modern technology rig.

“Rates will remain the same for the next three months, but I suspect they will pick up in the next six months. We will see an uptick by the first quarter 2015,” a mid-tier land driller told Hart Energy market intelligence surveyors.

Operators are moving to pad drilling in areas where the Niobrara has been delineated. Service providers cited the average number of wells per pad at five with as many as 12 or 13 planned for new deep Niobrara wells in the Piceance Basin.

Zipper fracs now account for 71% of completed horizontal wells on multi-well pads. Operators are using an estimated 1.9 million pounds of sand per well on average, or about 100,000 pounds per stage, with straight sand accounting for 82% of proppant consumed in the region. About 10% of proppant is resin-coated sand, survey responders told Hart Energy, with remaining 8% as ceramics. Sand volumes ranged from a low of 1.5 million pounds per well to 3 million pounds per well.

Contact the author, Richard Mason, at rmason@hartenergy.com