In the Appalachian Basin, home to the Marcellus and Utica shale plays, it’s not unusual for lateral lengths to reach 12,000 ft. That’s about 2 miles, or 34 football fields.

Some have gone even longer, surpassing 19,000 ft.

Drillbits are also drilling longer in parts of the Permian Basin, where some lateral lengths are around the 15,840-ft (3-mile) mark.

As E&P companies drill longer laterals in shale basins across the U.S., they are reducing costs per lateral foot—aided by improved downhole tools, directional drilling navigation systems and other technologies.

Drilling longer laterals also brings forth challenges, especially when it comes to transmitting data—challenges that many can’t afford to let linger with market forces and the nature of oil industry at play.

“As you get deeper it becomes more difficult to obtain reliable data to guide drilling operations,” Alban Duriez, telemetry product manager for Halliburton, told HartEnergy.com. “So that’s just the nature of things. As you go deeper pressure waves are attenuated in the well.”

Advanced technology aims to change that as operators continue to focus on maximizing value, safely reducing well time and saving money.

Halliburton said it improved effectiveness of mud pulse telemetry including areas where operations utilize friction reduction devices, which Duriez said can cause turbulence above the bottomhole assembly and alter the mud pulse signal.

The company recently launched a new measurement while drilling technology called QuickPulse. It aims to power through downhole interference by combining “directional, vibration and gamma ray sensors with a strong transmission signal,” the company said. “The system automatically prioritizes critical vibration, tool face and downhole inclination measurements enabling rapid drilling decisions. It transmits data in intervals as fast as three seconds and full survey measurements in as little as 24 seconds.”

Adjustments to the data rate can be made, if drilling conditions, mud properties, the rig or other variables prompt the need for a slowdown.

A key differentiator of the technology, Duriez said, is its ability to automatically decode the mud pulse in noisy environments without human intervention via advanced noise cancellation algorithms at surface. This includes areas where operations utilize friction reduction devices, which Duriez said can cause turbulence above the bottomhole assembly and alter the mud pulse signal.

In addition to transmitting directional data in real-time, the system provides gamma ray readings as well as three-axis vibration and stick-slip measurements.

“Three-axis vibration and stick slip measurement are becoming more and more critical to have because as we drill deeper we get more downhole friction, vibration, and these have high impact on the asset itself downhole and lead to significant damage, sometimes to failure,” Duriez explained. “Having the vibration and the stick-slip visibility allows us to monitor the amount of energy downhole that our tools are exposed to and react to it, change drilling parameters, so we can drill deeper, safer.”

The technology has already been run over 150 times in several shale basins, including in North Dakota’s Bakken, the Permian Basin and the Scoop and Stack Basins.

He recalled an instance when the technology was used for an operator in the Bakken, resulting in improved data rates and reduced well time.

“By having this very critical data, especially over the build section, the operator was able to drill a curve on one well in nine hours instead of 16 on average,” Duriez said, noting other components are critical as well. “You need a good mud motor; you need a good drill bit. We’ve got to be pragmatic about it, but having the right information at the right time is really key to make the right decisions and drive these records.”

He added that there has been demand for this type of service, which led to its launch.

But demand doesn’t necessarily equate to uptake in the industry where some E&Ps are slowing oil and gas activity to focus more on earnings growth.

The slowdown is already impacting oilfield service companies, including Halliburton.

“It’s certain that the economics of our industry today are very, very difficult compared to the past,” Duriez said. “Nonetheless, we had that in mind, so we’ve engineered a solution that addresses the needs of our customers, while helping to maximize their asset value.”

 

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