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Baker Hughes has introduced the new Lucida advanced rotary steerable service, which integrates hardware, software, automation, and remote connectivity to help oil and gas operators drill faster and deliver more precise, higher-quality wells.
The service is designed to maximize directional drilling performance and well productivity by incorporating advanced electronics and near-bit sensors that enable drillers to more precisely guide bottomhole assemblies.
The Lucida service fully complements Baker Hughes drilling automation and remote operations services, increasingly in demand as operators aim to reduce on-site rig personnel to improve efficiency and safety. More than 70% of Baker Hughes drilling operations in 2Q20 utilized remote capabilities, up from 60% in the first quarter and roughly 50% in 2019.
The Lucida service’s integrated bottomhole assembly (BHA) includes a customized drill bit and proprietary high-strength connections to maximize penetration rates. The BHA also includes near-bit sensors to gather more downhole data and multi-chip module electronics, which have been tested extensively at temperature cycles approaching 400° F to provide a step-change in reliability in more demanding drilling environments.
The service’s 16-sector gamma-ray sensors are situated close to the bit and provide real-time formation data that enable quick decisions to navigate the reservoir more precisely.
Lucida’s automated wellpath trajectory control system integrates both azimuthal and inclination hold modes with continuous proportional steering to automatically correct wellbore trajectory for formation trends.
Case study
In the Permian Basin, Texas, an operator was experiencing performance and reliability issues when drilling 6 ¾-in. slim hole applications, often requiring up to six bottomhole assemblies to complete a single well section.
Baker Hughes recommended the Lucida advanced rotary steerable service for this challenging application. The Lucida service drilled a 9545 ft lateral in 12.6 days versus an offset well that required 15.3 days, a 17% increase in drilling efficiency. The service also reduced average dogleg severity by 39%, delivering better wellbore quality than previous efforts.