In one application, 14 ¾-in. hybrid bit drilled 8,277-ft intermediate subsalt section while averaging 150 ft/hr on-bottom ROP
By Ryckman C. Callais, Jaime L. Butler, Baker Hughes
Polycrystalline diamond compact (PDC) bits and traditional roller cone bits can both face numerous challenges when drilling in the deepwater Gulf of Mexico (GOM). These range from poor drilling dynamics and gumbo-related-balling problems to drilling salt efficiently. The resulting nonproductive time (NPT) and compromised drilling speeds can challenge economic recovery in today’s environment. However, in Q1 2016, deepwater operators have used a new hybrid drill bit technology to reduce drilling times in extreme GOM wells.
Deepwater operators often prefer PDC bits for their perceived cutting superiority, directional control and the bits’ perceived ability to deliver higher rates of penetration (ROP) across a wide variety of drilling environments. However, a PDC bit’s inherent shearing action can lead to excessive downhole torque levels and fluctuations. It can increase the likelihood for other drilling dynamic dysfunctions, such as torsional and lateral vibrations and bit whirl, when used in the extremely long drill strings commonly found in deepwater GOM wells. In addition, PDC bits are more prone to stick-slip issues in deepwater wells due to their aggressive cutting structure and the variance between its maximum and minimum revolutions per minute (RPM).
Although roller cone bits can offer more stability than PDC bits in these applications, they face their own challenges when drilling through salt, gumbo or interbedded formations at a much lower ROP than PDC bits. Target reservoirs in the GOM deepwater are often located below thick sections of bedded salt and sub-salt formations. Additionally, drilling through these interbedded formations can often cause vibration issues and bit bounce. If not managed properly, these issues can shorten BHA run life and increase NPT.
Baker Hughes’ Kymera hybrid drill bit combines the rock-crushing strength and stability of roller cones with the cutting superiority and continuous shearing action of PDC bits. It is essentially a steel-body PDC bit on which the secondary blades have been replaced by rolling cutters. The central portion of the cutting structure is a conventional PDC cutting structure, while the bit’s nose, shoulder and gauge benefit from the combination of both rolling cone and PDC cutting elements. Having the roller cone design surround the hybrid bit’s outer structure assures smooth rotation while the bit’s fixed blades mechanically clean the borehole bottom and eliminate the tracking, which can limit ROP in conventional roller cone bits.
As a result, the hybrid bit can substantially increase ROP compared with roller cone bits and reduce the potential for bit bounce. Compared with PDC bits, durability is significantly improved in interbedded formations with less risk of stick-slip. Additionally, overall drilling torque levels are lower and more consistent, while stability and directional control are improved. Torsional oscillations, in particular, are often reduced by as much as 50% compared with traditional PDC bits.
Records with 26-in. bit
The hybrid bit – available from 5 7/8 in. to 28 in. – has already drilled 240,000 ft for 16 operators in the GOM. Running a 26-in. hybrid drill bit in three consecutive wells allowed one operator to set three successive ROP records and one total-footage record in a riserless batch drilling program 4,200 ft of water. Maintaining low levels of vibration and consistently high ROP were two key objectives, along with maintaining true verticality throughout. All three intervals were drilled with one bit on a conventional motor assembly and provided good directional responsiveness from the bit.
All of these goals were achieved, with the first interval drilled at 255 ft/hr. The second and third intervals were drilled at 307.5 ft/hr and 379 ft/hr, respectively. Compared with offset wells, seven days of drilling time was saved. Further, the third run broke the operator’s record for most footage drilled by a 26-in. bit in one 24-hr period.
Salt and sediment interval
In another recent GOM application in a water depth of 4,267 ft, an operator was facing severe vibration risks while drilling through 1,872 ft of sediment that contained at least one layer of balling-prone “gumbo” shale and 1,000 ft of salt. Directional control was also critical because failure to maintain verticality could result in a deviated wellbore. This would likely produce excessive torque and drag for the remainder of the well. Excessive vibrations could also cause premature downhole tool failure.
The operator’s objectives were to drill the interval using a single BHA, while avoiding excessive vibration and maintaining the well’s verticality. Additionally, the operator established an aggressive, on-bottom ROP target of 112 ft/hr. This would require averaging at least 125 ft/hr through the sediment and approximately 75 ft/hr in salt.
The ROP achieved with the 26-in. hybrid bit nearly doubled the operator’s goal for the sediment interval by drilling 245.2 ft/hr with negligible vibrations to establish a new on-bottom ROP record for the section. The ROP for the entire bit run – sediment and salt – averaged 205.5 ft/hr. Compared with offset wells, these ROP gains saved the operator more than $304,000; cost of the section was reduced by 39%.
Pre-salt cap formation
In another well located in 4,473 ft of water, a GOM operator was challenged with drilling a 3,300-ft section that consisted of three distinct intervals: a top section of shale and claystone, a 1,500-ft section of pre-salt cap and a 1,200-ft salt formation. The operator’s key drilling objectives for the well included providing a stable on-bottom drilling environment, minimizing vibrations and drilling the three sections in only two runs.
An 18.125-in. hybrid bit design was selected. The cutting structure of the cones was denser than on bits typically used for drilling salt in the GOM. This design also offered a tighter spacing between the PDC cutters for an increased cutter volume, and the cutter backrakes were adjusted to improve bit life. The bit’s PDC cutters also contained application-specific cutter edge geometries designed to reduce torque fluctuations and lateral vibrations while minimizing the risk of cutter breakage.
The bit completed the entire section in a single run – a first for the operator – drilling more than 3,300 ft in 78 hrs. The single run avoided a planned bit trip and eliminated up to five days compared with offset wells. The operator saved an estimated $6.1 million.
ROP of up to 300 ft/hR
In an ultra-deepwater well in 9,582 ft of water, a 14 ¾-in. hybrid bit was selected to drill an 8,277-ft intermediate subsalt section to TD. The section contained interbedded sand and shale, as well as the challenging Mio-Ash formation. The operator needed to complete the section within seven days as a dedicated trip was scheduled for a required BOP function test. Prior to this application, the best offsets in the field averaged 60 ft/hr, and the hybrid bit would need to achieve an average ROP of 75 ft/hr to complete the section within the given time period.
Issues with mud pumps and emergency systems on the drilling rig led to two days of NPT at the beginning of the section, further narrowing the time window. However, maximizing operating parameters of WOB and RPM enabled the hybrid bit to average 150 ft/hr on-bottom ROP. The entire 8,277-ft section was drilled to TD with 24 hrs to spare before the scheduled BOP test. The hybrid bit also achieved instantaneous ROPs greater than 200 ft/hr at many points while occasionally reaching 300-plus ft/hr. DC