PDC bits, motors help rotary steerable systems expand applications
Managing designer well plans
Diverse rotary steerable tool applications continue to emerge as unique drilling tool configurations are implemented. Advances in these tools and the development of complementary drilling bits, drilling fluids, and other associated drilling tools, are helping operators achieve success in geosteering, extended reach, and "exotic" well plan scenarios.
The AutoTrak™ tool line from Baker Hughes INTEQ (BHI) has managed to maintain leadership in this new wave of technologies, with more than 155 well applications. As of July 1999, the tool had recorded 17,700 tool operational hours for a total drilled distance of 609,000 ft, and a maximum depth reached of 25,150 ft. Single bit run records with 6 3/4 -in. and 8 1/4-in. tools, respectively, were 7,293 ft in 165 hours, and 11,881 ft in 98.3 hours.
BHI says the development of compatible polycrystalline diamond (PDC) bit technologies with Hughes Christensen (a sister company) is one of the reasons for an added increase in AutoTrak™ efficiency. Bit design parameters such as gage length, cutter, and placement design have been used to optimize tool performance.
Gage length has been found to be critical in optimizing the side force cutting ability of these tools. Shorter gage length offers smaller area and fewer cutters. This reduction in cutters, increases the unit force on each cutter, maximizing cutting ability. This added turning capability allows more aggressive dogleg gradients to be achieved.
BHI uses the following formula for dogleg gradient capability: Dogleg gradient = dogleg severity/% of applied force. Several factors are involved with the "applied force" of the equation:
- Bit design - cutter placement and density
- Bit wear - cutter wear or loss
- Rate of penetration (ROP) - inverse relationship with tool turning performance.
The faster the drill rate, the fewer rotations per ft for cutter contact.
Footage per bit run up
Rotary steerable and conventional steerable technologies were used in tandem to increase drilling efficiency in a known problem zone.
Since January 1998, the average footage drilled per tool run has increased by 80 ft each month, to a July 1999 high peak of 1,960 ft per bit run. Numerous interpretations behind this rate of increase are possible. Two interesting observations can be made from the data.
- The efficiency increase occurred in an extremely slow activity period. Fewer bit runs across the industry were available for tool use, but a steady footage increase was noted for this entire period. This implies increasing tool reliability in a very steep learning curve, and most importantly, raised operator confidence in the technology.
- Although there were fewer bit runs for the time period, the runs made were in more extended reach drilling situations, compared to new, exploratory well scenarios.
Designer wells play to the technical advantages of rotary steerable tools. A recent North Sea example used an 8 1/4-in AutoTrakTM in the same bottom hole assembly as an Ultra Series motor to drill through a geological problem zone, then set 9 5/8-in protective casing.
The conventional motor was used for added power and rotational speed on the 12 1/4-in bit. The bottom hole assembly configuration consisted of the bit, AutoTrak™ rotary steerable tool, non-magnetic pony collar, motor bit-box crossover, and the Ultra Series motor, run in a straight alignment. This configuration has been used numerous times with minimal axial wear observed to the motor bearing assembly or lower mandrel.
The 8 1/2-in production hole was geosteered as a horizontal wellbore through the heavily faulted reservoir section. High porosity zones were detected and geologically followed with realtime, triple combo formation evaluation measurements from the Navigator tool. The entire 3,267 ft of this horizontal section was drilled in a single bit run and 68.8 drilling hours. The average rate of penetration was 896 ft/day, compared with the planned 245 ft/day, an improvement of 365%. The shorter rig time required equated to $600,000 in saved rig costs.
A geosteering team at the well site used modeling software and realtime triple combo MWD data to predict the permeability of the reservoir and keep the well within the optimum, producing zone as the horizontal section was drilled. The final wellbore placement delivered a permeability of 409,000 millidarcy-ft, compared to the target of 250,000 millidarcy-ft. The increased permeability resulted in production rates exceeding 20,000 b/d.
Rotary steerable record
More extended reach applications and increased tool reliability have increased the average footage per bit run by 238% in the past six quarters.
The AutoTrak™ system was used to drill a planned 11,155 ft West of Shetlands well. More than 9,843 ft of the section was planned at a steep 79° inclination. Measurement-while-drilling (MWD) sensors were used to detect a potential gas cap along the well plan trajectory. Two potential problems observed in adjacent offset wells were excessive circulating hours spent for hole cleaning, and the inability to efficiently orient and slide conventional steerable assemblies near the end of the 8½-in. hole section.
The entire 11,881 ft of the 12¼-in. section was drilled in a single AutoTrak™ run, and 98.3 drilling hours. This effectively set a new world distance record for rotary steerable systems.
A rotary steerable compatible, Hughes Christensen TX447 bit, was used to yield exceptionally large cuttings and reduce the mud circulation requirements by 0.03 bbl/ft. Constant rotation of the drilling assembly eliminated sliding problems previously encountered. Hole inclinaton remained within
Upon detecting the potential gas cap with real time triple combo logging measurements, the AutoTrak™ system was used to drill a 2953-ft horizontal section through the reservoir in a single run. Logging-while-drilling (LWD) sensors were used to geosteer and avoid breaking into the gas cap. The average rate of penetration for the bit run was 127 ft/hr. To insure log quality, the final 820 ft of the bit run was control-drilled at a constant ROP. Effective use of this drilling system saved the operator six days of rig time and $1.5 million in rig and mud costs.
Step change improvement
A single bit run record of 11,881 ft was made in 98.3 hours of drilling.
Rotary steerable systems and complementary drill bits are eliminating many of the factors that restrict well planning in terms of complex well trajectory stepout and precise well placement within the reservoir.
As a result, the industry is experiencing a step change extension of the operating envelope and dramatic improvements in drilling efficiency and production potential. The growing range of tool applications allows companies to realize lower overall project costs, even with more costly drilling technologies. Smaller operating companies can now financially justify the use of some of these technologies.
Contributing to this article were R. Bitto and J. Haugen, both of Baker Hughes INTEQ.