Today’s unconventional challenges are a far cry from those of less than a decade ago, when a single shale well might have a 1,000-ft lateral and a few stages. Back then, the talk was all about achieving faster rates of penetration (ROP) with new directional drilling techniques to break through the hard formations. While those goals remain important today, operators have also moved on to more ambitious campaigns, characterized by deeper, more deviated and tortuous trajectories, tighter spacing between wells and, in the sizzling Permian Basin, stacked laterals.
For drilling contractors, that means the bar has once again been raised to deliver more robust solutions and heed a new set of watchwords: repeatability and predictability.
To meet these objectives, contractors have ushered in a new era of super-spec AC rigs featuring greater horsepower, higher pressure ratings, more hookload and expanded pipe-racking capacity. They’ve also designed sophisticated control systems that integrate a broad range of digitally powered functions to streamline the drilling process with more precision.
However, there are pockets where mechanical rigs are holding their own. “Eighty-five percent of today’s wells require super-spec rigs, but the conventional oilfield is still there, and it’s a money-maker,” said Jay Norton, President of Norton Energy. “A good rig with a fundamentally sound framework can be updated without rebuilding the entire machine.”
While rigs stood idle during the recession, many contractors did not, seizing the opportunity to prepare for this new wave of drilling by upgrading equipment and embracing technology in unprecedented ways.
Repeatability and Reliability
“We’re seeing lateral lengths continue to increase in every basin, with the current average length around 8,000 ft, up from approximately 6,000 ft in 2016. Extreme examples are as long as 20,000 ft in some basins,” Helmerich & Payne (H&P) President and CEO John Lindsay said. “Operators want to maximize reservoir exposure for each well, and those with large, contiguous acreage positions are routinely drilling 8,000- to 10,000-ft laterals. The long measured depth of this well profile is beyond the capacity of the typical 5,000-psi rating mud pump system. This can adversely impact performance of mud motors and rotary steerable systems, as well as cuttings removal and wellbore cleaning.”
First observing the trend toward longer laterals back in 2013, H&P began upgrading its fleet of FlexRigs to ensure higher levels of repeatability and reliability. These upgrades include 7,500-psi mud pump systems, increased setback capacity for longer measured-depth wells, walking and skidding capabilities for larger pads, and digital platforms for more autonomous drilling.
As drilling began to pick up in late 2017, the company reactivated 128 rigs, 91 of which feature Super-Spec upgrades. Since activating an additional 38 Super-Spec upgrades through the first three quarters of the fiscal year, H&P has more than 190 upgrades running in US land plays. If demand continues, Mr Lindsay said he anticipates adding 12 Super-Spec rigs per quarter.
“These upgraded rigs provide greater reliability and consistency, and they reduce risk to deliver better wells for customers,” he said, noting that the increased value being delivered by the upgrades has driven dayrates up in the past year, from the high teens to the low- to mid-$20,000s.
With more rigorous wellbore requirements putting a heavier burden on the directional driller, H&P has also integrated digital capabilities into its FlexRigs through two ventures aimed at improving well placement and wellbore quality.
The MOTIVE Bit Guidance System, acquired last year, uses modeling and automated decision making to more accurately steer the bit in real time by performing the calculations traditionally done by a directional driller. The financial interests of the operator drive decisions related to drilling speed, production and tortuosity.
“Historically, there has always been a desire to drill longer laterals, but the technical limitations in directional drilling execution resulted in friction that prevented us from transferring weight to drill effectively as laterals lengthened,” said Todd Benson, President of MOTIVE Drilling Technologies, a subsidiary of H&P. “Now, with technologies like MOTIVE, we can make more precise and repeatable directional drilling decisions that result in a smoother wellbore, dramatically reducing drag and enabling longer laterals while simultaneously placing the wellbore more accurately to maximize production.”
The system, designed with flexibility for use with various rigs and downhole tools, is running on more than 30 rigs, both FlexRigs and non-H&P rigs, and has been implemented on more than 500 wells. “We’ve seen that making more precise decisions results in less tortuosity, which enables us to drill faster at the end of the lateral, significantly reducing unnecessary trips in the curve,” Mr Benson said.
Magnetic Variation Services (MagVAR), also part of the H&P family, provides survey management technology to improve wellbore placement in longer laterals and reduce errors throughout the drilling process. It removes sensor error using mathematical modeling and more accurate localized magnetic referencing. “On a 10,000-ft horizontal, especially with the laterals spaced so close together, in some cases only 375 ft, there is a high probability that wells are closer than what is ideal or too far apart. This variability is due to survey error, which can impact communication between completion technologies or negatively affect the well’s hydrocarbon potential,” Mr Benson explained.
Mega Pads, Omnidirectional Walking
Independence Contract Drilling’s entire young fleet of ShaleDriller rigs features all the super-spec attributes. Many of them operate in the resource-rich Permian Basin, the epicenter of US land drilling where stacked plays and laterals up to 3 miles long require the most highly technical equipment available. Most of the company’s rigs have omnidirectional walking capabilities to move efficiently from well to well and even pad to pad, said Chris Menefee, Vice President, Business Development.
“Pad-optimal – 7,500-psi circulating system, AC drive, omnidirectional moving capability, 1,500-2,000 hp – are in demand because of the continued shift toward ‘mega pads,’ ” he said. “In 2012, most of our work was on pads with one to three wells. In 2014, we co-developed a 35-well pad with a customer, and now this approach is being considered by many operators across the major US shale basins.”
The downturn helped drive this trend, Mr Menefee noted. “Operators have invested millions to make their acreage positions contiguous through mergers and acquisitions, allowing them to take advantage of the operating efficiencies provided through these high-density pads. They can plan longer term and fully develop these resources by focusing CAPEX dollars on drilling and producing wells, rather than moving rigs.”
Whereas the first generation of mobile land rigs were skidding rigs that moved in just an X/Y direction, the ShaleDriller fleet features 360° walking systems. “Recently, one of our rigs walked 462 ft in less than six hours for a customer in the Permian Basin, a milestone that proved the technology. By moving from one pad to the next, anywhere from 100 ft to 100 yards, operators can reduce their cycle time and avoid the time and cost of rigging up and down,” Mr Menefee said.
Among the biggest changes is the move from 5,000-psi to 7,500-psi pressure ratings on mud pumps to handle increased downhole pressures as laterals get longer. “Some operators require three mud pumps, versus two, either to have a standby pump in case one fails, or to run three pumps in the hole at all times. All our rigs have 7,500-psi equipment, and we can add a third pump depending on the customer’s drilling requirements.”
Alongside the physical upgrades, digital analytics are playing an increasing role in rig designs as operators seek greater control of the drill string and associated downhole tools to drill more precise wellbores and push lateral wells ever farther.
“We’ve come a long way, even over the last two or three years, as drillers get better and understand the software we’re utilizing,” Mr Menefee said. “The downturn made all of us focus on consistency and getting better at what we do. Today, drilling complex laterals has become a science, using data and facts as opposed to the ‘art’ of drilling we’ve relied on for years, trusting our gut. We cannot afford to make mistakes and must use all the information and technology available to us. As we learn to rely on data, we will be more consistent and, therefore, more efficient.”
All ShaleDriller rigs have the ability to collect and use data. “Not all operators necessarily require data analytics software, but as the software creates value, we are finding more operators are willing to pay extra to utilize it. These programs allow drillers to control ROP, pump pressures and directional tools with greater consistency. Now, with a younger generation of drillers using a more scientific approach, the industry will drill even more complex wells with less cost and higher productivity.”
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