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.”
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