Ros Davidson reports on the growth of so-called “super-spec rigs” as US drillers push for faster wells and longer laterals
The media is abuzz with news of “super-spec rigs” – the monster structures that have taken the US’ unconventional plays by storm. As operators demand greater efficiencies and longer laterals, suppliers are now in a race to upgrade equipment, grab market share and reap the benefits of the super-sized equipment.
Executives from Helmerich & Payne (H&P) as well as Patterson-UTI and Nabors Industries – the big three land rig companies – all referenced the importance of super-spec rigs earlier this year in their Q4 2017 earnings calls, as did smaller companies such as Xtreme Drilling, the Canadian rig supplier.
The term ‘super-spec’ emerged amongst investors and rig suppliers a few years ago. H&P defines such a machine as a land rig with AC drive, 1,500 horsepower, 750,000-pound (340-tonne) hook load, pad capability and high-pressure, 7,500-psi mud systems. They are typically used for horizontal drilling in unconventional plays where thousands of feet of pipe have to be handled for a complex drilling operation – it is not simply a case of lifting the pipe, as would be the case for a vertical well.
Overall, Patterson-UTI estimated that there were around 550 super-spec rigs working in the US – each with 95% utilisation – CEO Andy Hendricks said in February. An investor presentation from H&P in the same month suggested that 40-41% of land-use oil and gas rigs in the US would be classified as super-specs.
Those extra capabilities command higher prices. Indeed, the spot market for super-spec rigs hovers around US$20,000-25,000 per day, and their continued popularity means that market remains very tight. Even more rigs are expected to be upgraded to super-spec capability in 2018.
Although every driller is different, a glimpse at capital costs came from H&P, which runs the biggest fleet of super-spec rigs in the US, in its latest earnings call with analysts. Executives said that the 30 of its flagship FlexRigs – an AC-drive rig – currently active today could be upgraded to super-spec status in the field with an investment of US$2 million to US$3 million each.
The addition of a walking package – a system allowing it to move quickly between wells – might cost an operator in the region of US$8 million. That is in contrast to constructing a super-spec rig from the ground up, which could cost close to US$25 million. According to Patterson-UTI, the cost of building its own fleet of high-spec rigs back in 2014 and 2015 ranged from US$22 million to US$24 million.
H&P, which upgraded 16 rigs in the final quarter of 2017, estimates it owns about half of the 200-250 rigs in the US that could be relatively easily upgraded to super-spec. “If customer demand remains, and we're able to achieve reasonable pricing, our upgrade cadence could average 12 or more FlexRig upgrades per quarter,” H&P president and CEO John Lindsay commented in late January. Again, the gains in doing so can be significant: rig owners can charge an extra US$2,000-3,000 daily if a rig is super-spec. H&P has already increased capex spending by between US$50-100 million, in part to fund super-spec upgrades.
The road to MADness
The rigs, sometimes as tall as 16 stories, are typically outfitted with high amounts of digital control and automation. They usually controlled by a single, cabin-based operator with access to sensors, automated brackets, a hydraulic catwalk and iron roughnecks (an automated system for screwing pipe together).
A 750,000-pound hook load capability – equivalent to the weight of a fully-laden Boeing 747 – is crucial as the industry gets accustomed to the routine of laying so-called “super-laterals” of 15,000 feet (4,500 m) and over.
Indeed, greater lateral length is the single main driver behind the hot market for super-spec rigs, according to H&P’s Lindsay. “Lateral lengths have increased to the extent that this is pushing the limits of the standard AC drive rig fleet,” he said. “In 2017 the average lateral increased another 15% to approximately 8,000 ft [2.4 km], and we expect this trend of longer laterals to continue. As a reference point, the average lateral in 2015 was approximately 6,000 ft [1.8 km].”
Evidence of this can be seen in the development of so-called mile-a-day (MAD) rigs, capable of drilling 5,280 feet (1,600m) of rock in 24 hours – a ceiling only in place as a result of the friction of the drill.
Moving these rigs from one drilling location to another is getting faster in another way too, despite their scale. Many can typically walk, or be self-skidding, on feet that can weigh as much as 10 tonnes each. Improvements in these pad drilling systems mean that some super-spec rigs can often be moved in just 48 hours, half the time that may be required by older models.
Even when remobilising completely, these rigs have been designed for ease of movement. Earlier this month, Xtreme Drilling president and CEO Matthew Steven Porter told analysts that, not counting drill pipe, the company’s super-spec 850XE rig was engineered to be moved from one location to another in 39 truck-loads – approximately 20% fewer loads than most super-spec rigs.
Need for speed
Despite their eye-popping specs, these rigs are not actually the result of a step-change in drilling equipment or in the application of the technology, according to Colorado School of Mines associate professor of petroleum engineering Bill Eustes. Instead, they are the result of the gradual evolution that is always taking place in the equipment for the industry – albeit an evolution that has become more pressing as low prices have forced operators to become more efficient.
“Every new rig has a new wrinkle,” says Eustes. “It’s everything you can do to make time irrelevant. Speed! Speed! Speed!” he said of the latest trends in rig equipment, speaking with InnovOil via phone from his truck as he travelled en route to the school’s experimental mine near Idaho Springs. “It’s also a question of safety – so that fingers, arms, heads and legs are not in danger.”
Some of the recorded improvements in drilling time are indeed remarkable. In Colorado’s Denver Julesburg formation, a super-spec rig can now drill an 18,000 foot (5,500m) well in seven days – whereas the same job used to take three or four weeks. A decade ago, in the Pinedale Anticline in Wyoming, a 14,000 foot (4,270m) well might have taken 60 days from spud to rig release, but nowadays could take as little as six days, Eustes says.
Moreover, the ability to apply these new technologies means the process of drilling itself is constantly improving. Surface holes may now be drilled in a batch, then the equipment is changed out, and the drilling will resume, also in a batch.
So what might the future hold for the next generation of rigs? Twenty years from now rigs will be more automated, says Eustes, and there will be more operational and reservoir related data analysis.
Automation will likely be applied to tripping, for example, when the drillstring is pulled in and out of the wellbore, a repetitive and time-consuming process. There may also be a move to full automation of drilling rock, and even automated construction of the wellbore itself. While a well-trained crew can still outperform a rig with today’s level of automation, expert labour can be in short supply depending on the drill site, and fatigue also becomes an issue. Although it may lead to fewer high-speed records, increased automation would make operations far more predictable, consistent and safer across the board.
There will be improvements to drilling fluids and drill bits too, and lasers might be used for penetrating rock. Laterals will become longer. A 10,000 foot (3,000m) lateral may be routine now, and a 15,000 foot horizontal well is occasionally achieved, but within two to three years, Eustes says that 15,000 feet will be routine and operators will be pushing for 20,000 feet (6,000m).
Increased electrification could also see quieter rigs deployed in urban areas – a process that is already happening today. If a rig can be run off the grid, then the need for noisy and polluting diesel generators is eliminated. “You just need to be near three-phase power,” adds Eustes.
Despite the incremental gains in heavy equipment, Eustes says that the sensors used to measure parameters such as weight, torque or rotational speed may still be a limiting technology in the near term. Although they provide useful data streams, they are not yet that precise – though this too will change soon enough, he says. The field will also grow to include sensors better able to operate in extremes of heat, cold or wet, all of which should improve the quality of data and decisions drillers can make.
As InnovOil has often heard, the oil and gas industry is seen to be behind the curve on data analysis, he adds, especially in terms of gathering and applying data from drilling performance and characteristics. Expertise too is still in demand; while there may be authorities in drilling and in data analysis, Eustes says, too few are experts in both.
Looking out to 2018 and into 2019, the trend in North America certainly appears to be increasing demand for longer laterals and higher-spec rigs, with no sign of a slowdown of upgrades or utilisation. The real battle now will be for market share, as drillers vie for super-rig supremacy.