Overview of Subsea Production Systems - Oil and Gas Wells

A: Start with velocity: 15 L/min through a 19 mm ID gives roughly 0.9 m/s. That puts Reynolds near the laminar–turbulent boundary for a 3 cP fluid. Using Darcy friction with f around 0.03 and 12 km length lands you in the tens of bar range. Option A feels reasonable if you lock onto laminar flow, but Re isn’t low enough to justify it. Option C borrows intuition from production lines, ignoring that umbilicals are long and narrow. Option D overcorrects by treating the line like microbore tubing; the diameter isn’t that small.

A: Convert 8,000 BPD to about 233 gpm. Standard liquid Cv is Q·sqrt(SG/ΔP). Plugging in gives a value in the mid-teens. Option B looks tempting if you slip into kg/hr, but Cv is volumetric. Option C assumes viscosity correction dominates, which it doesn’t at moderate oil viscosity. Option D mixes a design philosophy with an actual calculation and inflates the result by an order of magnitude.

A: Line ID verification first avoids cross-pressurizing the wrong actuator. A controlled pressure test below full MAWP catches leaks and blockage before motion. Option B saves time but assumes wiring and plumbing are correct, a bad bet with illegible drawings. Option C reverses the logic; pressure without knowing the destination is how actuators get overloaded. Option D sounds gentle, yet gas compressibility masks resistance and can spike loads when switching fluids.

A: Gas lift changes inlet phase behavior, often increasing liquid carryover. Pulling back gas lift addresses the source. Option B feels proactive, but it can destabilize downstream flowlines if the root cause persists. Option C manipulates pressure, risking hydrate margin loss. Option D delays action until a subsea issue becomes a topsides problem.