Overview of Subsea Production Systems - Oil and Gas Wells

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.

A: Catenary geometry sheds a lot of vertical load, but not all. Hundreds of tonnes is the right scale. Option A assumes perfect decoupling, which isn’t real. Option C treats the riser like a rigid vertical string. Option D overstates buoyancy effects; they reduce but don’t erase load.

A: At 120 bar, hydrate equilibrium temperatures are well above ambient seabed temperatures. That creates a large driving force. Option B confuses hydrates with ice. Option C flips the pressure effect; higher pressure promotes hydrates. Option D ignores the role of free water and pressure, over-focusing on composition.

A: Visual confirmation catches misalignment and debris, the usual failure modes. Option B skips the chance to prevent seal damage. Option C applies to flying leads, not production jumpers. Option D is desk assurance; it doesn’t tell you what happened offshore.

A: Higher ΔP at fixed conditions points to reduced area. Option B sounds optimistic but contradicts the physics. Option C is possible, yet two independent measurements often show the same trend. Option D affects ΔP slightly, not abruptly.

A: An 8-inch line holds about 0.032 m³ per meter. Multiply by length and count and you land near 2 m³. Option B adds CA incorrectly to ID. Option C swaps wall schedule into the volume basis. Option D uses OD, inflating inventory threefold.

A: End-to-end checks expose wiring and configuration gaps early. Option B is efficient but blind to field terminations. Option C defers discovery into a hazardous phase. Option D assumes documents reflect reality, a risky assumption in brownfield work.