Petroleum Reservoir Engineering

A: Option A tracks the combination that actually matters: dissolved CO2, liquid water, and elevated temperature pushing carbonic acid kinetics. B sounds tempting if you fixate on pressure alone, but with negligible H2S the SSC mechanism doesn’t initiate. C borrows a failure mode from surface systems; oxygen ingress isn’t credible in a sealed reservoir environment. D becomes dominant only when sand rates and velocities are high, which isn’t stated and wouldn’t replace electrochemical attack as the life-limiting mechanism here.

A: A follows the barrier logic: the valve’s job is isolation, not rate control, so its failure removes a layer against blowout. B confuses chemical damage with barrier failure; souring needs sulfate and biology, not an open valve. C sounds operationally plausible but jumps from failure mode to long‑term damage without a mechanism. D imports a multizone completion assumption that isn’t inherent to a single safety valve.

A: A comes from keeping units straight: area to m², bulk rock volume to pore volume, applying oil saturation, then dividing by FVF. B typically drops the saturation term or misuses porosity as a percentage. C looks reasonable if you forget to convert km² or double‑count net pay. D often appears when FVF is mistakenly multiplied instead of divided, shrinking the stock tank volume.

A: A reflects how low‑ppm H2S is managed: control hardness and stress rather than jumping materials. B is attractive because 13Cr is common, but at this temperature and with H2S present it’s not automatically safer. C overreaches; CRAs are selected when severity justifies cost, not on trace gas alone. D imports a seawater narrative; chlorides aren’t the controlling variable downhole here.