Overview of Well Fluids - Oil and Gas Wells

A: Governing principle: mixture density follows phase volume fractions at flowing pressure and temperature. At 600 psig most of the gas is still free but occupies far less volume than at standard conditions, while oil remains the continuous phase; that pulls density down from stock tank oil but nowhere near gas-like values. Option A traps engineers who compress scf to acf correctly but forget oil still occupies most of the pipe volume here.

A: Governing principle: small amounts of H2S fundamentally change CO2 corrosion behavior in wet systems. At 200 ppmv H2S you’re below classic SSC thresholds but high enough to disrupt FeCO3 scaling, leading to higher general corrosion rates than sweet service alone. Option A catches people who size the CO2 partial pressure correctly but ignore how even trace H2S alters film chemistry.

A: Governing principle: sour service is defined by H2S partial pressure in the presence of water, not by vendor labels. At 150 ppmv H2S with free water, ISO 15156 applies regardless of someone calling it 'sweet', and it drives metallurgy and hardness limits. Option D tempts engineers who live in piping codes and assume corrosion is implicitly handled there.

A: Governing principle: for two incompressible liquids, bulk density approximates a volume-weighted average. 58 lb/ft³ sits much closer to water than oil, but linear interpolation between 50 and 64 gives roughly one-fifth water by volume. Option B catches those who eyeball midpoints without actually running the ratio.