Introduction to Directional Drilling - Oil and Gas Wells

A: A build rate stated in degrees per 30 m is already a curvature metric when azimuth is steady. Option B sounds reasonable if you're mixing up inclination change per joint with spatial curvature, but that drops a factor of three. Option C is a trap from horizontal turn calculations where azimuth and inclination both change. Option D imports BHA stiffness into what is a purely geometric check; stiffness affects achievability, not how dogleg severity is defined.

A: Continuous rotation is what keeps tortuosity down, which is why option A aligns with casing wear concerns. Option B is common offshore and looks attractive for build, but the aggressive bend spikes local doglegs. Option C works in many fields, yet sliding introduces micro-doglegs that don't show up well in planned curves. Option D assumes predictable bit walk, which falls apart once formation changes.

A: Stopping rotation and going to pumps-off addresses trajectory uncertainty but doesn't restore cooling, so bit heat remains a live issue. Option A feels obvious because surveys stop, yet anti-collision relies on last known position and offset rules. Option C still exists, but no rotation means no new curvature. Option D disappears once sliding stops; without toolface control, nothing is being steered.

A: High tensile stress plus H2S is the classic setup for sulfide stress cracking. Option B tempts anyone used to production tubing, but drilling mud chemistry and exposure time are different. Option C happens during storage or bad mud handling, not sustained downhole drilling. Option D is real in high-rate wells, yet it doesn't explain cracking failures seen during trips.