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Why People Make A Difference In Drilling Efficiency

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January 24, 2013

“Man ain’t nothing but a man
But before I’d let that steam drill beat me down,
I’d die with a hammer in my hand.”
--Woody Guthrie, John Henry

The land drilling industry is undergoing debate on its own version of an American folk tale about the steel-driving legend of John Henry versus the machine.

You recall that legend, probably through the Woody Guthrie song, but the short version tells the story of a steel-driving crew foreman who constructs tunnels for the railroad in the 1870s when the railroad owner decides to replace the crew with a steam-powered hammer. To save his job, John Henry challenges the owner to a race between his crew and the steam-powered machine. John Henry wins — thus creating a heart-warming American folk tale — only to die of a heart attack at the finish line.

A similar legend is unfolding today in the concept of drilling efficiency, the latest buzzword in the oil patch. Like most legends, the story, now embellished, is largely over when the tale hits the public-discussion phase. But the issue is the same: What counts more for efficiency gains in drilling unconventional shales — is it iron (technology rigs), or is it people?

A newly published Tudor, Pickering, Holt & Co. study confirms that the John Henry-versus-the-machine legend is, in fact, an apt analog when it comes to rig efficiency. Experienced crews and the ability of the industry to capture learnings in unconventional plays over time accounts as much for drilling efficiency improvement as the class of rig.

More on that study in a moment, but first some background.

Drilling efficiency surfaced in a big way in Eagle Ford shale during the summer of 2012 as one operator after another outlined how improvements in drilling cycle time enabled their companies to meet well targets with fewer rigs.

Since then, the drumbeat on rig efficiency has hit with rhythmic regularity at industry conferences and generated thousands of words in trade publications. Rig efficiency is not a new topic, though the frequency at which the concept was discussed accelerated with the 2010-11 newbuild rig push as operators ordered fit-for-purpose rigs to meet developmental programs in unconventional shales. Previously, the debate had been parochial to publicly held service providers in the land sector, often at investor conferences, during the first decade of the 21st century following the debut of advanced technology rigs, now colloquially referred to as joystick rigs.

Those building technology rigs, initially Tulsa-based Helmerich & Payne IDC (NYSE: HP), but eventually Nabors Industries Ltd. (NYSE: NBR), and Canadian drillers including Ensign Energy Services, Inc. (TOR: ESI.TO), Precision Drilling Corp. (NYSE: PDS) and Trinidad Drilling Ltd. (TOR: TDG.TO) vigorously touted the benefits of joystick rigs while traditional contractors, including many privately held firms, noted that efficiency in drilling was really about experienced crews — John Henry — rather than iron.

Until the global commodity-price downturn in 2008, investors were split on the issue. Investors who liked the concept favored Helmerich & Payne, which ranked a distant third at that time behind Patterson-UTI Energy and Nabors in domestic rig count. Investors who felt that newbuild rigs also saddled publicly held drillers with excessive capital costs that harmed competitive advantage — and therefore investor returns — liked commodity rig companies such as Patterson-UTI Energy, the nation’s number one driller before the 2008 drilling market collapse.

When the dust cleared from a ruined domestic drilling market in 2009, the John Henry-versus-the-machine story changed. Helmerich & Payne emerged as the nation’s leading driller as operators switched from conventional to unconventional shale drilling with a greater emphasis on extended reach horizontal wells, the type of drilling that favored technology rigs. Ultimately, it became a matter of joining them, if you can’t beat them, and Patterson-UTI, for example, now markets its own joystick technology rigs.

A Rig Is A Rig Is A Rig?

The truth of the matter is that rig efficiency is about more than just the rig. Even when the conversation focused on the rig, the story initially focused on mobilization. Technology rigs were modular in nature, often using trailer-mounted designs that date back to the 1970s, and moved between wells more quickly than standard box-on-box rig designs, providing operators with incremental wells over the course of a year. In other words, the initial time saving accorded to drilling efficiency was due to mobilization rather than technology per se.

Operators still note that drilling efficiency gain is not only about the rig, but also about greater hydraulic horsepower, improvements in downhole motors, better bits and advances in rotary steerable technology, none of which are proprietary to a given service provider or rig class.

Similarly, the move to newbuild technology rigs was as much about the evolution in fiscal terms between service providers and customers as it was about the availability of efficient technology. The advent of iron-clad multiyear contracts, first pioneered by Grey Wolf Drilling more than a decade ago in the domestic land market, played an important role in enabling the advent of technology rigs. Through term contracts, service providers could recoup most of their costs in constructing newbuild units over the life of the contract. For operators, term contracts meant pricing was locked in, adding predictability to development costs, while guaranteeing access to a rig in high-demand environments like the 2007-08 era.

Additionally, operators were able to work with contractors to develop “fit-for-purpose” units under the multiyear contract regime that were adapted to long-term specialized development programs in unconventional or tight formation oil and gas plays.

The result was two eras of new rig construction. The first, from 2002 to 2008, occurred as demand for land drilling services accelerated after offshore gas production fell and operators began early exploitation of tight formation natural gas in the Rockies and the Barnett shale to make up the difference. The second newbuild effort unfolded in 2010-2011 as oil and gas operators began ordering fit-for-purpose rigs as drilling efforts in the new shale plays evolved from optimization to resource harvest.

And that leads back to the John Henry story where Tudor Pickering Holt (TPH) picks up the modern narrative.

“Our analysis shows well cycle time improvements across all rig power types and horsepower categories, thus implying the human experience factor has played a meaningful role in moving well time/depth curves to the left,” according to the report, which was released in January 2013.

The study found that performance varies early in unconventional play development with first movers experiencing advantages versus their peers. However, those advantages dissipate over time. In the Williston and Eagle Ford shale plays, the study found, that the variance between the fastest and slowest contractors was 10 days in the Williston Basin (Bakken shale) and 16 days in the Eagle Ford shale three years ago. By the third quarter 2012, variances shrank to three days in the Williston and two days in the Eagle Ford.

“As these plays move to full development mode, the low-hanging fruit (learning curve) has been picked and we believe industry will need to turn toward other sources for additional well cycle time improvements,” according to the TPH report.

The report argues that the shift toward AC-powered rigs versus older mechanical and DE-SCR electric rigs will provide some additional gains. However, days to drill, when indexed by rig power type across rig classes, including AC-powered (joystick) rigs, traditional electric DE-SCR rigs and conventional mechanical rigs, registered nearly identical improvements between the first quarter 2010 and the third quarter 2012 in terms of percentage gain, regardless of unconventional play. Similarly, those gains were identical regardless whether the rig featured a 1,000 HP drawworks or a 1,500 horsepower drawworks.

So if the iron improves in performance over time, and all iron improves, in fact, at roughly the same rate, what accounts for the gain? The TPH study found the answer in human factors after looking at performance variances between contractors. Like the startling answer at the end of the 1973 science fiction movie Soylent Green, “It’s people.”

“For instance NBR (Nabors) has outperformed the industry average in the Williston and HP (Helmerich & Payne) outperformed in the Eagle Ford. We think the root cause of this outperformance is experience,” according to the TPH study. “NBR has drilled the most wells and holds the largest market share in the Williston while HP has maintained the greatest share in the Eagle Ford. We believe the combination of greater experience in the play and a larger physical presence (logistics, infrastructure etc.) versus competitors typically results in drilling outperformance in the earlier stages of a play’s development.”

Still, the TPH study sees a continued evolution toward joystick rigs in the future, though most of the gains from a percentage basis are tied to just a handful of unconventional basins.

“Absent a sustained natural gas price rebound, we expect many of these SCR and mechanical rigs to remain idle, while higher-quality AC rigs return to work.”

There are financial implications for investors who have soured on the land drilling sector. The TPH study notes that Nabors had the most higher-spec underutilized equipment at the moment, and thus a better upside versus peers if the drilling market improves in 2013.

Though not stated explicitly in the January 2013 TPH study, another theme is evident in the rig efficiency story. Namely, the industry captures gain on the rig side early in the development of unconventional oil and gas plays. Afterward, it is a matter of diminishing returns. Once the industry transitions into the resource-harvest phase, efficiency improvement at the rig level becomes harder to come by.

Dropping from 45 days to 25 days when drilling a well is one thing. Moving from 25 days to 20 is another. And moving from 20 to 17 is another thing altogether. After the initial gains in drilling efficiency, improvement in well cycle originates from process and completion. And once every one begins discussing improvements in drilling efficiency, those gains have largely been captured.

In fact, drilling efficiency improvements resemble a hyperbolic curve similar to the rapid production decline evidenced in play type curves. Most of the goody is gotten early, only in drilling efficiency the cause of the improvement underscores the distinctly human aspect in oil and gas.

“They took John Henry to the graveyard

Laid him down in the sand

Every locomotive comin’ a rolling by

Hollered, there lies a steel-drivin’ man.”

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

Tudor, Pickering, Holt & Co. | Nabors Industries | Ltd | Helmerich & Payne | Patterson-UTI Energy | Nabors | Tudor Pickering Holt | TPH | NBR | HP

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