Drilling advances

To remain on the good side of the budget guardians, it would be wise to avoid leaving a multi-million-dollar BHA in the hole—a lesson often learned the hard way, when a drillstring is fitted with improperly designed stabilizers.

So says Exxon Mobil, which, during a root cause analysis of field failures, found that many anomalies, ranging from stuck pipe to vibration-induced drilling inefficiencies, could be traced to the stabilizers. The results of that investigation led to the development of comprehensive stabilizer selection guidelines that provide manufacturers engineering specifications aimed at enhancing drilling efficiencies, while ensuring that the same BHA run in the hole is pulled out intact.

Paul Pastusek, drilling mechanics advisor for the Drilling Technical Group of Exxon Mobil Development Company, said the guidelines cover all pertinent design and manufacturing components, including taper angle, wrap angle, bypass area, stabilizer pad diameter, stabilizer blade pad pressure, fabrication methods, material specifications and transition radii. “Basically, what we’re telling vendors is ‘here’s what we’d like to see on our rig floor,’” Pastusek told a January meeting of the SPE Gulf Coast Section in Houston.

“Our objective is to drill a round hole to bottom, minimize vibration, incur no unplanned dogleg severity and get to the geological target at the end. This seems really simple, but we don’t do that,” he said. “We vibrate, we leave ledges in the hole; it’s never round and, quite often, under-gauge as well.”

Moreover, Pastusek said a section ideally will be drilled in a single BHA run with no noticeable stabilizer torque and drag, thereby clearing the way for tripping on elevators without having to rotate and ream back out of the hole. Eliminating the surface friction factors of the BHA—including stabilizers, which contribute heavily to reduced drilling rates and, at worst, degenerate into destructive whirl and stick slip—would, he said, go a long way toward achieving those objectives.

“I don’t know exactly what value it needs to be, but I can sure bet that a low-friction OD is good for everything I need to do, including running in and pulling out of the hole. Also, if I had an extra 10,000 ft/lb of torque, I could drill faster. I have a number of rigs that are drilling at 100% top drive capacity, but only 10,000 ft/lb of that is getting to the bit. If I can get another 10,000 ft/lb, I can double the ROP, which is a very big deal in these long ERD wells. I can’t think of anything bad about lowering friction on the OD.”

Vendor checklist. Pastusek says Exxon Mobil’s ongoing failure analysis was the genesis for the stabilizer selection guidelines, which were conceived to provide manufacturers specific design criteria. While admittedly a work-in-progress, the latest iteration covers all facets of stabilizer engineering and manufacturing.

For instance, taper angles of less than 30° are ideal, but Pastusek said 30°–45° tapers are acceptable, if they pass the muster of a technical review. “We want nothing greater than 45°, because if you put it in the hole, chances are you won’t get it out,” he said. Spiraled wrap angles of less than 360° are specified to avoid pack-offs and the need to back-ream while tripping out, which is especially critical in high-angle wellbores.

Another guideline stipulates a bypass area greater than 35% for smooth hole diameters, and higher than 25% in smaller holes, which will enable tripping on elevators through cuttings beds. “Generally, if the bypass area is a bit larger than the cuttings bed area, I can trip out on elevators,” Pastusek said as justification for the bypass specifications. “In bigger holes, you easily can leave a 20% cuttings bed area, which, of course, is much less in smaller hole sizes, where the drill pipe fills up most of the hole.”

Stabilizer pad pressure, as a rule-of-thumb, should be held around 300 psi, which will accommodate the use of any hard facing material. Also, near-bit pad diameter should be designed from 1/16-in. to 1/8-in. under-gauge, while farther up the string, the specified diameters range from 1/8-in. to 1/4-in. under-gauge. “We never run full-gauge stabilizers, as you can wipe out the filter cake and also have a good chance of getting stuck,” he said.

Designing active cutters on the stabilizer OD is a definite no-no. “They tend to grab, and the friction on the OD will generate reverse whirl. Anything that creates an extra tangential force on the OD is bad for me. They may clean up ledges, but they’re deadly for vibration, so the key is to drill a round hole to begin with,” he said. Depending on the size, Exxon Mobil has adopted a ¼-in.-to-1/2-in. transition radius for the blade’s leading edge, thereby avoiding the risks of an overly sharp blade destroying the filter cake.

As for the fabrication methods and material specifications, Pastusek said the check list calls for non-welded, solid-body stabilizers in all 171/2-in. or smaller diameters. The only material requirement is that it must meet or exceed API Spec 7-1 specifications.

Moreover, along with the design, Pastusek said spacing can be adjusted to reduce vibration while meeting operators’ optimum rpm ranges. “If I strum a guitar, I get a certain note, and if I hold down a fret, I get a different tone, as it’s vibrating to a different natural frequency. If I take a drillstring and space the stabilizers one drill collar apart, or 30 ft, and then I change it and put in a pony collar, I’ve added an extra 15 ft, so now it’s 45 ft of spacing and that gives a lower frequency.”

“I can adjust the natural frequency at which the BHA will vibrate by adjusting the stabilizer spacing. We can design it to be quiet.” 

About the Authors

Jim Redden

Contributing Editor

Jim Redden is a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.