Fewer, Better, Land Rigs

When it comes to new capacity in the U.S. rig market, two clichés describe the industry in transition. The first is, “What a difference a year makes.”

Turn back the page to second-quarter 2011, when publicly held land contractors announced an astounding 83 newbuild rigs during earnings season, most accompanied by a term contract of three years, or longer.

The composition of the U.S. onshore rig fleet changed between 2008 and 2012 as wells grew more complex. Newbuild Tier I rigs accounted for a greater level of rig count as total measured depth of wells expanded in tandem with a growing percentage of nonvertical drilling in unconventional plays.

That number was notable, because the land industry had averaged a steady 20 to 30 new-build rig announcements per quarter since January 2010. Furthermore, the second-quarter 2011 breakout was followed by announcements of 41 newbuilds in third-quarter 2011, en route to 174 announced newbuilds for 2011 among public drillers. Privately held drillers were building another four dozen new units. When the smoke cleared, U.S. contractors had announced more than 320 newbuilds during the 2010 to 2011 era. Fleet retooling had come of age with a vengeance in the land rig drilling industry.

Fast-forward a year: oil services investors heard only the sound of crickets from land drillers when it came to newbuild announcements. The drillers instead spun a frustrated narrative involving rig oversupply and softening day rates that was expected to last into 2013.

“We do not yet foresee a sharp downturn, but rather, a moderate drop in rig count exacerbated by competitors offering uncontracted, newly built and existing rigs at lower rates and shorter terms in order to secure work,” Nabors Industries chief executive Anthony Petrello told investors during the company’s second-quarter conference call. “We are also seeing operators farming out rigs they are committed to under term contracts.”

In fact, the buzz switched to operators at midyear 2012, many of whom observed that improvements in drilling efficiency meant they would drop incremental rigs by year-end. And that leads to where we are today. The basic story for the domestic land fleet is that the industry is moving forward with fewer, better rigs. Efficiency gains now enable operators to meet their drilling program targets faster, within existing budgets, and with fewer rigs.

“In the Bakken, we improved drilling cycle times by approximately 30%; in essence, we are accomplishing more with less,” Continental Resources chief executive Harold Hamm told investors during the company’s second-quarter earnings call.

Marathon Oil chief executive Clarence Cazalot echoed the theme. “A real success story is being seen in the Eagle Ford, where we’ve continued to reduce the time needed to drill wells. We’re now in a position to drill and complete our target number of wells with 18 rigs, rather than ramping up to 20 as planned with the Paloma acquisition,” Cazalot told investors during the company’s second-quarter earnings call. Marathon had a 50% reduction in Eagle Ford drilling cycle time in the past year.

Both comments were part of a barrage of operator observations highlighting rig efficiency gains during the second quarter and detailing multiple examples of wells that once took 45, or 50, or 70 days to drill that were now being drilled in half the time, or less.

It turns out there is evidence to support the anecdotes. At press time a Tudor Pickering Holt & Co. drilling study found spud-to-release time improving 18% in the Eagle Ford shale from January 2010 to the present. The Williston Basin witnessed a modest 3% gain, while the Marcellus improved 15% across all horizontal wells.

A rig-fleet makeover

Those observations are reflected in the changing composition of the U.S. land rig fleet. Once upon a time, a 750-horsepower (HP) drawworks, conventional mechanical rig with 1,000-HP mud pumps, was enough to drill 65% of onshore wells. The new standard is a minimum 1,000-HP drawworks, electric rig with 1,300-HP or higher mud pumps. The sweet spot in the rig industry nowadays involves a draw-works of 1,500 HP, some 750,000 pounds of hoist capacity, and two or more 1,600-HP mud pumps. Those are the units that can drill 65% of today’s onshore wells.

Nonvertical drilling as a percentage of rig count rose from less than half of 2008 peak activity levels to more than 70% of 2012 activity.

This evolution in rig specification mirrors the rise of unconventional drilling domestically. You know the story: the industry is evolving from conventional vertical wells, often targeting natural gas, to unconventional directional wells targeting wet gas or oil. Today’s well profile is characterized by a steady rise in total measured well depth, with more than 70% of the rig count focusing on nonvertical wells.

Consequently, the U.S. rig fleet is adapting to new types of wells. This transition has created a colorful suite of terms for an ever-expanding industry lexicon. Where the land drilling industry used to reflect a Gertrude Stein simplicity in which “a rig is a rig is a rig,” new terms today are tossed about with casual impunity. Rigs are divided into tiers, reflecting differing specs and power systems. Contractors trademark terms like super singles or super triples. There are fit-for-purpose rigs. There are even specialized “walking” rigs.

But mostly there is a tiered terminology when it comes to rig differentiation. For example, a Tier I rig refers to a unit typically configured with a top drive, automated casing and pipe-handling equipment, and sophisticated digital instrumentation to control the drilling process on a fast-moving modular package often powered by AC-VFD electric systems. Tier II rigs are the older electric DESCR units, while Tier III rigs are conventional mechanical units, once the bread-and-butter unit in the contractor’s arsenal.

Drilling contractors employ their own terminology and informally label Tier I units as joystick rigs, referring to the air-conditioned cabin (sounds rustic, doesn’t it?) where a driller sits in an oil and gas version of an electronic Barcalounger, watching multiple computer screens attached to a high-backed faux-leather swivel chair, using touch-screen dexterity and the joystick attached to one of the chair’s arms to control rig operations.

The evolving nature of the domestic rig fleet is also evident in the fact that the number of rigs assembled from recycled parts over the past half decade has essentially disappeared as the old fleet reaches the end of days. Furthermore, retirements of older, mostly smaller mechanical horsepower rigs are increasing—the number topped 157 among public drillers at the end of 2011—while a rising number of new-builds offset rigs, mostly conventional mechanical units, were removed from the fleet. With overall fleet numbers declining slightly over the past two years, according to the annual NOV Downhole Census, the fleet is evolving to include a greater share of higher-spec electric rigs with greater capacity to drill the industry’s more challenging directional wells.

Those changes are further reflected in the rig count, where Tier III conventional mechanical rigs shrank from 50% of the active rig fleet in 2008 to 40% currently. Simultaneously, Tier I technology rigs—the joystick AC-VFD units—grew from 14% of the active rigs in 2008 to 28% of the current market.

The unconventional cycle

But the trend in 2012 is less about disruptive change than it is about the evolution of the 2010-2011 cycle into a different phase. This new phase reflects maturation in unconventional resource development as the industry transitions from new resource discoveries and efforts to capture leased acreage, into full development mode.

A review of the unconventional development cycle offers insight into why industry comments changed so dramatically between second-quarter 2011 and second-quarter 2012. Unconventional plays undergo a series of phases beginning with discovery and transitioning through delineation and optimization to resource harvest.

The annual NOV Downhole fleet census shows the net number of rigs removed from the onshore fleet growing while those assembled from parts virtually disappears, indicating the end of the line for spare capacity. In order for the U.S. fleet to grow, contractors must build rigs.

Each of these phases has different rig requirements. Discovery and delineation are rig agnostic as long as a rig meets basic performance specs. Operators are conducting basic science or attempting to capture acreage. The cycle evolves into optimization after a couple years, or into experiments to find what works best in terms of well design, including lateral length and frac stages. At this point, operators look at specific rig capabilities. It is during this phase that operators achieve the largest gains in rig efficiency. Once operators figure out the formula, the unconventional cycle transitions into the resource harvest phase, which promises savings from repeatability and economies of scale.

While the unconventional drilling cycle may begin with a commodity rig, it evolves towards rig specialization, which is evident in terms such as “fit-for-purpose” rigs, or units configured for specific drilling parameters, such as in the Marcellus shale in Appalachia. Often these include onsite mobility, or walking packages, particularly as the industry transitions into pad drilling configurations where multiple wells or multiple horizontal laterals are drilled from a single well site, such as we see in the Bakken shale. At this point, a drilling program evolves from a $7- to $10-million well to a $40- to $50- million industrial program, capturing efficiency gains. That context explains recent operator comments about needing fewer, better rigs. Their comments also illustrate which basins are entering the resource harvest phase of unconventional development.

A driller employs touch-screen technology just an arm-length away on Nabors Drilling Rig M-52 at work in the Austin Chalk in July 2012. Modern Tier I joystick rigs enable drillers to monitor systems activity and control rig operations from a swivel chair in a climate-controlled cabin.

Rig fleet futurama

There are caveats when discussing the evolution of the U.S. rig fleet. Like the rapid depletion curve in unconventional wells, rig efficiencies improve quickly for operators early in the play’s evolution but level out after a couple years. At that point efficiency gains transition to the completion phase. The TPH drilling study confirmed this thesis in noting that significant gains in mature plays like the Barnett and Fayetteville shales in the 2008-2010 time period tailed off in the past couple years to incremental improvements.

Inset, Nabors Rig M-52 is one of 550 Tier I AC-VFD rigs in the U.S. land market.

Second, smaller rigs are not destined for extinction. In plays like the Fayetteville, Marcellus, and Permian Basin, a symbiotic relationship develops in which smaller, cheaper rigs drill the vertical shaft and larger, more expensive higher-spec rigs complete the horizontal laterals, which can be as long as 5,000 feet and longer.

Third, efficiency gains are mostly restricted to horizontal drilling and often due to operator choices on better bits and downhole motors that provide significant increases in the rate of penetration. The TPH study found there were only minor improvements in vertical wells over the past five years.

Additionally, a new trend is under way in which unconventional drilling techniques are applied to shallower, legacy oil plays. The play adding the most rigs currently is the Mississippi Lime, which, counter-intuitively, is employing smaller-horsepower conventional mechanical rigs in horizontal drilling, thanks to shallower depths and less intensive downhole requirements. This has led to a modest revitalization in demand for 750-HP conventional mechanical units, or even smaller-horsepower doubles units.

Ultimately, the U.S. rig fleet will reflect the style of wells operators drill, rather than conform to a rigid list of rig specs. When it comes to future capacity in the U.S. rig market, it is the second cliché that tells the evolving story of the U.S. rig fleet. Namely, the more things change, the more they stay the same.