Reservoir Engineering Fundamentals
Core rock and fluid properties
Candidates must be fluent in porosity, absolute and effective permeability, wettability, capillary pressure, and relative permeability. Relative permeability curves control fractional flow, and water saturation reaches irreducible saturation at the left endpoint. On the fluid side, understand PVT relationships: formation volume factor Bo (reservoir bbl per stock-tank bbl), solution gas-oil ratio Rs, gas z-factor, and viscosity trends with pressure. Keep reservoir volumes and surface volumes strictly separate.
Volumetrics and material balance
The volumetric OOIP equation and the general material-balance equation are exam staples. Know drive indices (solution gas, gas cap, water drive) and how each affects pressure decline and ultimate recovery. For gas reservoirs, use the p/z plot; for oil, track producing GOR (Rp) and water cut.
Flow and well performance
Darcy radial flow, skin, productivity index, and pseudosteady-state flow. Permeability averaging depends on flow geometry: arithmetic for parallel layers, harmonic for series flow.
Traps
Unit conversions (1 acre-ft = 7,758 bbl), applying Bo in the wrong direction, forgetting the (1 − Sw) term, mixing psia and psi, and using arithmetic averaging for vertical flow. Gas questions often require z-factor and temperature in degrees Rankine.
Worked example
OOIP = 7,758 · A · h · φ · (1 − Sw) / Bo. With A = 640 acres, h = 20 ft, φ = 0.20, Sw = 0.25, Bo = 1.2 RB/STB: 7,758 × 640 × 20 × 0.20 × 0.75 ÷ 1.2 ≈ 12.4 MMSTB.