Basic Reservoir Management

A: Option A walks the full chain: 640 acres × 50 ft gives 32,000 acre-ft. Multiply by porosity and So, convert acre-ft to reservoir barrels, then divide by Bo to get stock tank barrels. Option B sounds tempting because porosity feels like a volumetric shrinkage term, but Bo never cancels; dropping it inflates reserves. Option C undercuts itself by swapping net for gross pay; that’s conservative language masking a unit mistake. Option D flips Bo the wrong way around, a classic phase-basis error that quietly overstates OOIP.

A: Option A ties the symptoms together: stable BHP with early water points to near-wellbore vertical communication and coning driven by drawdown. Option B explains water, but edge-water usually shows pressure support and a slower ramp. Option C fits decline but not the rapid water cut shift. Option D happens in the field, but it doesn’t create true water production; it just distorts measured rates.

A: Option A runs the back-of-envelope: fractional depletion of 5% per year divided by total compressibility lands in the few‑tens of psi range. Option B drops rock and water compressibility, a common shortcut that breaks at reservoir scale. Option C feels safe but throws away most of the storage term, overshooting badly. Option D ignores how stiff oil-rock systems actually are; small fractional withdrawals still move pressure.

A: Option A follows Archie as written: Sw^n = (a·Rw)/(Rt·φ^m). Option B is the trap of linear intuition; Archie is exponential for a reason. Option C sneaks in default exponents that don’t match the stated rock. Option D reads the log qualitatively and skips the math, which is how saturation errors creep into models.