DIAMONDS ARE A DRILL’S BEST FRIEND
A team of researchers is working to compile a compendium of geothermal bits to help industry identify the right bits to use for which jobs, thereby reducing drilling costs.
Written by Michael Abrams
Sandia National Laboratories mechanical engineers David Raymond, right, and Melanie Schneider pose in Sandia’s Hard Rock Drilling Facility with a polycrystalline diamond compact bit. They recently completed an analysis on bit performance for geothermal well drilling. Photo: Craig Fritz
WHETHER IT’S DRILLING FOR oil and gas or geothermal wells, a longer lasting bit means both greater efficiency and savings. “Drilling is a very expensive undertaking,” said David Raymond, a mechanical engineer at Sandia National Laboratories. “And if you’re changing the drill bit all the time, you’re spending a lot of time not drilling—you’re not advancing a hole.”
That’s why the geothermal industry has, for decades, pursued the development of polycrystalline diamond (PCD) compact bits.
At the start of the century, synthetic diamonds were finally approaching the hardness of natural diamonds, making them the new bit material of choice for the oil and gas industry. But to get to rock suitable enough for geothermal purposes, drill bits have to grind through harder, hotter rock.
While today’s bits are harder than ever and there are many bit options for anyone hoping to drill down to hot rock, the geothermal industry has remained resistant.
To prove just how effective today’s PCD bits are and how their usage might be tweaked on the fly for the speediest possible well drilling, Raymond and fellow Sandia mechanical engineer Melanie Schneider set out to collect data on 100-odd bits put to work at Sandia’s FORGE site in Utah.
“Our work covered four of those wells and they were all drilled to a depth of about 9,500 to 10,000 feet,” Raymond said. Working with the University of Utah, they acquired bits, largely off-the-shelf models, from the major bit manufacturers such as Baker Hughes, ReedHycalog, and Ulterra, among others.
“These companies essentially offered their best effort bits based on what they thought would work,” Raymond said. The team tested and and monitored the bits as they drilled four wells at FORGE, with 30 bits being used on each of the 10,000-foot wells.
“The motivation was really to demonstrate that with commercial off-the-shelf technology, they can be used in geothermal—and that with the right people doing it and monitoring the data, you could actually demonstrate well construction with this technology,” he explained.
Each bit was worked as hard as it would be in the field—basically until it was worn out of usefulness. Researchers replaced bits when their rates of penetration dropped off.
Sandia National Laboratories mechanical engineer Melanie Schneider holds a polycrystalline diamond compact bit. Despite decades of research at Sandia and elsewhere, only recently have such bits become viable for geothermal well drilling. Photo: Craig Fritz
“The end goal of this is really to have a model that can be used in real time to make decisions, so that the drillers can control the parameters.”
—Melanie Schneider, mechanical engineer, Sandia National Laboratories
With geothermal drilling, vibration and abrasion from heat are bigger problems than they are for oil and gas drilling. Drill bit manufacturers tackle those two issues in multiple ways. The arrangement of diamond cutters can vary as can the nozzles that provide the lubricating mud. Carbide buttons can be added to absorb some of the vibration. The amount of cobalt can be reduced in the diamond making process to change how they respond to heat, but that can change the cutters impact resistance. “Like many other things in engineering, there’s tradeoffs,” Raymond said.
The team plans to complete a review of which bits performed the best, but the greater utility of the study is the collection and use of the data it provided. This compendium of data includes the speed, torque, and rate of penetration, among other parameters.
“The end goal of this is really to have a model that can be used in real time to make decisions, so that the drillers can control the parameters,” Schneider said. “They can control the weight on bit and torque, understand what that will do at the bottom of the hole, and improve performance by changing each of these parameters.”
Researchers perform drill bit testing at Sandia National Laboratories’ Hard Rock Drilling Facility. Video: Ruth Frank
The feedback loop offered by such a model would happen in real time. Measurements made at the drill site will be uploaded to a web server and analyzed from an off-site office.
“Measurements are available to people who are experienced with how the bits should respond, but they’re also made available to the people that are on the rig, controlling the drilling process,” Raymond explained.
Eventually that’s how the system will work. But the model, as it stands, was built after collecting data from the drill bits in action. Eventually, fresh data from live drilling will inform the model, and analysis and feedback will occur immediately.
“That’s still a little bit of a ways away, but that’s ultimately our goal—to understand how what we can control at the surface can improve performance of the bit,” Schneider said. “We’re at a good point in technology where there’s not a whole lot of improvement you can make on the drill bits. But at the surface, there’s a lot more that we can understand and use to improve performance and make sure that we can extend bit life so that we’re not having to replace them as often.”
Michael Abrams is a technology writer Westfield, N.J.
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