![]() Traditional rotary steerable systems operating in these extreme conditions require the limiting of drilling parameters and can experience a higher failure rate. In some areas, operators are forced to drill through tough interbedded formations to reach hydrocarbon s, often requiring higher mud weight and more extreme drilling parameters. The HyperSteer drill bit technology with the iCruise X intelligent rotary steerable system. The stiffer assembly, robust iCruise X RSS design, and HyperSteer drill bit have eliminated trips in the lateral to address damaging vibration, increasing the single BHA to TD success rate.įig. Since the drilling campaign began, the combination of the iCruise X RSS and the HyperSteer drill bit technology has been used to complete 10 curves without a flex assembly, with multiple runs reaching TD with a single BHA. The operator continues to use the assembly. Additionally, the shorter and stiffer RSS allowed the MWD survey and LWD sensor measure ment points to be closer to the bit, permitting more precise control and more accurate wellbore placement. Removing the flex joint also meant a stiffer BHA in the lateral and reduced vibration, with instantaneous ROP exceeding 350 ft/hr. The simulated capabilities of the iCruise X RSS with HyperSteer drill bit technology were validated during the first field run by achieving doglegs of 10°/100 ft in the curve without a flex assembly, Fig. HyperSteer bit technology achieving higher doglegs without a flex assembly with the iCruise X intelligent rotary steerable system. When the operator our firm ran the new HyperSteer drill bit with the iCruise X RSS using simulation software, the maximum DLS increased by 2°/100 ft, allowing for the flex joint assembly to be removed while still land ing the curve on target per the directional plan.įig. , compared to the traditional bit design, while simultaneously improving stability with a slightly increased gauge length. HyperSteer drill bit technology reduced makeup length by 2.1 in. The design incorporated learnings from our company’s Cerebro ® in - bit sensor and used Juggernaut® PDC cutter technology. The Halliburton team designed a customized drill bit to deliver the DLS requirements of the curve without a flex assembly to maximize ROP in the lateral that followed.Ī new bit design featuring HyperSteer drill bit technology was designed for the application. With a planned lateral section of approximately 10,000 ft, limits to the ROP had considerable effects on the overall well construction time and costs. While this bit with a flex assembly could drill the curve section, the flex assembly could potentially limit the maximum weight on bit and ROP in the lateral. The simulation determined that, using a traditional drill bit, a flex joint was necessary to achieve the DLS of 10°/100 ft required by the application. bit with six blades and 13-mm cutters was simulated on the iCruise X intelligent RSS assembly to determine steerability and maximum dogleg severity ( DLS ) capability. They design ed a solution that could help the operator reliably and repeatedly achieve these objectives.ĭuring the planning stage, a traditional 6.75-in. To meet this challenge, a local, application-specific engineering team was employed. To meet the directional plan, the assembly needed to yield between 8° and 10° dogleg per 100 ft while still being able to achieve instantaneous ROP in the lateral, upward of 350 ft/hr. ![]() hole required an RSS assembly to complete a curve and drill the lateral in a single BHA at a high rate of penetration ( ROP ). C ombined, these technologies increase the success rate of completing even the most challenging wellbores in a single BHA.Īn operator in North America drilling a 6.75-in. Halliburton continues to improve tool reliability and capabilities to achieve these goals with the iCruise ® X i ntelligent r otary s teerable s ystem ( RSS ) and the HyperSteer ™ directional drill bit line. T o reduce drilling time, the assembly must also be robust and stable at high weight on bit (WOB) and torque on bit (TOB ), to help prevent damaging vibration that can ultimately lead to a n unplanned trip. The higher build rates require larger force output from the rotary steerable sys tem (RSS), a more steerable bit, and a directional - friendly BHA. The industry continues to strive for higher build rates in the curve section and overall reduced drilling time, to maximize asset value. Signif icant efficiencies are gained by combi ning sections, and it is not uncommon fo r the vertical, curve, and lateral all to all be drilled using a single BHA. Today, m any operators face a similar drilling challenge: to T o optimiz e the bottomhole assembly (BHA), to drill multip le wellbore section s in a single run.
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