Land drillers usher in era of super-spec rigs

Operator demands for repeatability, predictability lead contractors to push ahead on horsepower pressure ratings, hookload and pipe-racing capacity while adding smart, data-analytic functions to control systems

By Kelli Ainsworth Robinson, Associate Editor, and Katie Mazerov, Contributing Editor

With the industry’s steady, albeit gradual, emergence from the dark days of the downturn, onshore drilling contractors are seeing rig counts rise and dayrates climb. Increasingly, drilling companies are deploying fleets of upgraded rigs to meet operators’ demands to achieve more reservoir contact with longer laterals from bigger pads.

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.”

Robust Rigs, Smart Systems

Nabors, one of the first developers of AC rigs early in the shale boom, has defined a new tier of high-spec rigs, the Nabors SmartRig fleet. Its PACE X750, X800, M750, M800 and M1000 rigs all incorporate increased setback, high-pressure mud systems and integrated walking packages. “Beyond the capacity of the rigs, what makes this fleet ‘smart’ is the Rigtelligent control system, which provides automation for repetitive tasks at the surface and automation of complex tasks that improve downhole efficiency,” explained Edgar Rincon, Vice President, US Operations. More than 90 rigs in the continental US meet the SmartRig requirements, and an additional eight to 10 will be deployed by the end of the year.

The newest design is the PACE M1000 rig series, four of which are operating in the Permian and Eagle Ford. All feature three 1,600-HP mud pumps; 7,500-psi mud systems; four engines, each rated at 1,476-hp; 1,000-kip hookload capacity; omnidirectional walking capability for multiwell pads; high-capacity drawworks for faster trip speeds; and 900-kip setback for racking 30,000 ft of 5 1/2-in. pipe and 35,000 ft of 5-in. pipe.

“In addition to safety, operators are focusing on two priorities: the time required to deliver the well, typically measured from spud to rig release, and the quality of well placement – location relative to plan and minimal tortuosity,” Mr Rincon said. “Solutions must be scalable and keep a tight control on costs. We believe the challenges of today’s wells cannot be met simply by expanding the capabilities of physical assets. Delivering safe, consistent and reliable performance requires a combination of assets, sophisticated software and control systems, automation, data aggregation and processing and competent personnel.”

Drillers face a multitude of issues that vary from play to play. These include high downhole temperatures, fluid gains and losses, longer laterals with closely spaced wells due to multiple horizons and layered formations, higher hydraulic horsepower requirements to clean the hole and wellbore placement difficulties. “A key factor for success is to operate the rig so that it protects the bottomhole assembly from premature failure in the long laterals,” Mr Rincon added.

The modular control system provides the ability to standardize and scale existing and future automation features to all SmartRig units. “For example, as managed pressure drilling (MPD) systems are becoming more prevalent, we have integrated MPD controls into the control system platform,” he noted. “This responds to the growing need for services to address fluid gains and losses, control gas, optimize ROP, decrease time for conditioning mud and reduce excessive torque-and-drag and stuck-pipe incidents.”

Nabors’ walking MPD-Ready rigs integrate rig controls, surface sensors and software to determine downhole pressure environment limits and manage annular hydraulic pressure while drilling.

The company’s CRT-Ready system facilitates running casing to bottom without the need for independent casing-running tool systems. The Directional-Ready rigs integrate downhole equipment and rig controls to ensure precise placement in extended-lateral wells. SmartRigs are further enhanced with the Navigator directional drilling platform for more accurate directional drilling decisions, and the ROCKit Pilot system, now in final testing. The latter will automate decision execution for automated, closed-loop directional steering.

Complicated: The New Normal

Integration of automated rig systems to optimize the process of drilling a well is a priority for many contractors. “Rigs historically were behind the curve when it came to automation and control systems,” said Sean Halloran, Vice President, Well Site Technology group for Ensign Energy Services. “However, the downturn provided a chance for companies to undertake development. Complicated is the new normal. With the availability of data and analytics, we can have richer conversations with customers around what is possible.”

Five years ago, the company began developing Ensign EDGE, which integrates rig controls, data analytics and communication to optimize performance for the overall well construction life cycle, ultimately improving ROP and other parameters. “Bringing these automated features into one cohesive ecosystem delivers more value,” Mr Halloran said. “Across the unconventional plays, we’re drilling twice the footage in the same amount of time. The challenge is to maintain repeatability so we can deliver on key performance indicators.”

The control system is currently installed on 35 of the company’s large AC and smaller hydraulic rigs. Approximately 90 of Ensign’s 170 global rig fleet are currently working. As idle rigs go back to work, with SCR rigs retrofitted with AC top drives, they will be outfitted with the EDGE system.

“With this evolution, we own the brains of the rig in a modular software package that allows various disciplines to communicate in a common language,” Mr Halloran said. “By introducing process automation and repeatability, we’ve reduced connection times to less than three minutes slip-to-slip, an improvement of 100% in some cases and more than 50% in most cases.”

In the Permian, Ensign’s high-spec AC walking rigs are seeing the most demand as operators require higher torque on the top drive, higher pressure from mud pumps and the ability to rack back more pipe. On one Permian well, the control system reduced drilling time from 14 to eight days. Earlier this year, an ADR super-spec rig equipped with the EDGE control system in Alberta set a record drilling Canada’s longest land well, at a measured depth of 25,492 ft (7,770 m), in 14 days. The system also is being implemented in Argentina’s Vaca Muerta formation.

Ensign’s fleet of ADR 200 and 300 rig series consists of agile and highly automated hydraulic rigs that excel in tight formations, drilling shallower wells with lateral extensions. The rigs are working in California, Oman, Western Canada and Australia, drilling coal seam and traditional wells. In Bakersfield, Calif., ADR 300 rigs typically drill 2,000 ft in one day and move to the next well within 24 hours. The rigs, which are easily transported in urban areas, have a highly automated drilling floor, with tubulars delivered and aligned with the well center by an automated pipe arm and connections made with an automated iron roughneck.

An emerging trend with larger rigs is the use of batteries with natural gas engines, which don’t accelerate as quickly as diesel engines. “Batteries provide immediate acceleration, then back off so the engine can take over, providing more consistent power,” Mr Halloran said, noting that Ensign once had the largest fleet of natural gas rigs. The practice fell off during the downturn, but this year the company plans to re-introduce a hybrid rig to prove the economic model that it saves fuel, reduces emissions and provides better control on the rig.

Updating Old-Style Rigs

For the conventional market, Norton Energy is modifying its fleet of eight 800- to 1,000-hp mechanical rigs to accommodate horizontal drilling in the San Andres formation in the northern part of the Permian Basin. Laterals there are typically 1 to 1 ½ miles, with measured depths ranging from 10,000 to 13,500 ft and total vertical depth 4,800 to 5,300 ft.

“Traveling north, the Permian becomes shallower, with dolomite versus the stacked shale layers of the Midland and Delaware basins,” Mr Norton explained. “Our customers don’t need 7,500-psi super-spec rigs to drill these shallow horizontal and vertical wells and don’t require walking systems because each well has its own pad.” The same is true for the shallower, gassier part of the Eagle Ford and areas of Oklahoma.

“Five years ago, we realized our conventional jack knife rigs were going to become dinosaurs, so we built a new mast to rack back more pipe for horizontal drilling,” he continued. The mast incorporates a permanent top drive that stays in the derrick even while moving. Mechanical mud pump capacity also was increased to 1,600-hp and 5,000 psi, from 1,000-hp and 3,500 psi, to move more fluid in the laterals. The 900-hp drawworks is proving to be more than adequate for drilling these wells, with maximum pressure around 3,500 psi.

“These rigs endured from the 1940s to the mid-2000s because they are so efficient and move easily,” Mr Norton said. “By adding some higher-spec equipment and better technology to the existing framework, we have a rig that can handle this work.”

Four carrier rigs, which operate on seven axles with scope-up style masts, also have been upgraded with top drives and double, versus triple, racking configurations to accommodate the top drive and handle 13,000 ft of pipe. The company’s last carrier-style Kelly rig is drilling its last shallow vertical well in the San Andres formation in Hockley County, and then will be replaced by a similar rig with a top drive that will initially drill seven vertical wells.

Operators do need rigs that move quickly and efficiently, Mr Norton said. “We try to stay agile for quick rig-up and down. None of our rigs take more than a day to move, and even our doubles can be moved and rigged up in a half a day. We move off a well every 10 to 11 days.”

Looking ahead, Norton Energy is positioned for further upgrades as the need dictates. “We will be in the AC business eventually and can even add walking systems. Iron roughnecks and hydraulic catwalks are being incorporated, and at some point we will add electric-powered pumps and AC drawworks,” he said.

“In the past six years, the industry has gone from an exploration/exploitation model to one of manufacturing long-lateral wellbores that require significant technical skill to hit the sweet spots. It’s no longer about drilling a dry hole. It’s about how productive we can make that lateral.” DC