An application-specific bit technology has been quickly adopted, primarily in the US unconventional shale gas plays, leading to improved performance and reduced drilling cost, according to a presentation made by Matt Isbell of Baker Hughes at the 2010 IADC/SPE Drilling Conference on 3 February in New Orleans.
The growing importance of unconventional gas onshore US has become apparent, with a significant number of rigs switching from conventional drilling to drilling in shale formations. “ Each of the shale plays has different efficiencies, different drilling applications, that result in their time on well. All of the operators in all the plays are trying to get these times down,” Mr Isbell said.
In order to achieve that, more and more bits are becoming application-tailored based on individual needs. “Matching the technology for a bit to a given application is pretty easy for one bit. But when you think about the well programs that are going on, we’re talking about … hundreds of designs, thousands of bits and even more bit runs,” he said.
The application-specific drill bit designs include fit-for-purpose features such as improved stability, steerability, optimized hydraulics, depth-of-cut control, diamond volume management, and wear- and durability-optimized cutters.
“One of the other interesting things about wells in the shale plays is that, because you’re just looking at three discrete intervals – vertical, curve and lateral – we’re often able to get these bits now to drill the interval in one run. That’s kind of the ideal case,” Mr Isbell said. “And in fact, that’s one of the reasons the Barnett is so efficient. In the past, we used to see a little bit of wear and damage on the bits. Now they’re coming out brand-new.”
The company tracked the performance of the first 50 new-technology bits implemented in applications in the US, primarily in the shale plays. Several case studies were presented.
In one run from the Barnett, the objective of the interval was to drill out from surface casing and maintain a tangent angle on steerable motor assembly at a high ROP. The challenge was to enhance bit stability in order to reduce impact damage from drilling with a steerable motor. Using a new-technology bit, this run saved the operator 17 hours of drilling time and more than $28,000 in drilling costs.
Another run in the same county in Texas was in the pre-kick off interval of a well in the Atoka sand and Bend conglomerate formations. The objective was to hold a tangent well path on a steerable motor to reach kick-off point (KOP) while drilling through the formations. Challenges were identified as maintaining bit steerability to achieve directional requirements, ensuring an efficient cutting structure through the run despite the highly abrasive formations, and limiting impact damage through the conglomerate interval with enhanced bit stability. The new PDC bit achieved an average penetration rate that was almost 90% faster than the average of offsets while drilling to KOP. This saved 35 hours of drilling time and more than $58,000 in drilling costs.
In one Haynesville case study, a bit run began at 8,364 MD and was pulled for achieving KOP at 10,516 ft MD. Many updated stability features were used on this bit, as were impact-resistant cutters. A total of 58 hours of drilling time was saved, as well as more than $97,500 in drilling costs.
“This technology is being accepted quite rapidly. At the time that we wrote the abstract (for this paper), we were down around 0.2% of the overall footage in US land. And it’s actually hovering around 15% as of January,” Mr Isbell said. “So in terms of the ability of the industry to take this new technology and adapt it into new techniques, new drilling results, has been quite impressive.”