PetroSmart Academy | Synthetic teaching case | Version 1.0, 25 October 2026. This is a reproducible educational model, not a field development approval or an independently certified design.
Follow one consistent dataset through inflow, surface liquid handling, voidage replacement, pump power and a simple five-year cash-flow model. Prerequisites are productivity index, formation volume factors, pressure work and discounted cash flow. Values are declared assumptions, not measurements.
Reservoir pressure is 300 bar, flowing bottomhole pressure 240 bar and assumed bubble point 180 bar, all absolute pressures. A linear single-phase oil productivity index is 20 STB/day/bar. Water cut is 25% of stock-tank liquid volume. Oil and water volume factors are 1.25 RB/STB and 1.02 RB/STB; injection water has 1.02 RB/STB. Surface rates must use consistent stock-tank reference conditions. RB denotes reservoir barrels; it is not interchangeable with STB.
Oil rate = 20 × (300 − 240) = 1200 STB/day. Total liquid = 1,200/(1 − 0.25) = 1600 STB/day; produced water = 400 STB/day. The assumed 1,800 STB/day liquid capacity is not exceeded. Both reservoir and flowing pressures exceed the assumed bubble point, consistent with the selected single-phase reservoir inflow model. This does not establish the tubing outflow or separator conditions.
Withdrawal = 1,200 × 1.25 + 400 × 1.02 = 1908 RB/day. Injection of 2,000 STB/day gives 2,040 RB/day, so VRR = 1.0692. This ratio suggests a volumetric surplus under the declared accounting boundary; it does not independently predict pressure. Produced-gas accounting is omitted because no separate gas phase is withdrawn at reservoir conditions in this idealized case. If a measured surface gas rate were introduced, its solution-gas component would need reconciliation before adding free-gas voidage.
Assume the actual liquid volume at pump suction equals the stated stock-tank volume, neglecting thermal expansion and any gas. The full 1,600 bbl/day liquid stream passes through a pump that supplies 40 bar differential pressure at 70% overall efficiency. Convert barrel volume using 0.158987294928 m³/bbl. Shaft power = QΔP/η = 16.82 kW. The 40 bar is an independent surface-system requirement; it is not inferred from the reservoir drawdown. NPSH, gas carry-under, viscosity, pump curves and pressure losses are not assessed.
Assume 90% availability, constant rates for five years, oil price $60/STB, variable cost $25 per STB of oil, fixed operating cost $2 million/year, initial investment $25 million and abandonment cost $3 million at the end of year five. Taxes, royalties, financing, escalation, working capital and residual value are excluded. Prices are hypothetical and not a market forecast.
Annual oil = 394,200 STB. Annual operating cash = $11.797 million. Five-year NPV at 10% = $17.857 million; the conventional-cash-flow IRR is 36.19%. These are conditional model outputs, not an investment recommendation.
Change productivity, water cut, injection allocation, pressure requirement, availability and price separately. At 40% water cut with unchanged oil rate, liquid becomes 2,000 STB/day and exceeds the assumed facility capacity: the base production assumption can no longer be retained without a revised model. Constant pressure and rate require a justified reservoir forecast; the five-year flat case is a teaching scenario, not a history-matched prediction.
Before field use, add nodal analysis, time-dependent reservoir behavior, separation/PVT reconciliation, pump/vendor checks, integrity limits and actual fiscal terms. Reproduce the calculations with calculations.py and inspect outputs.json. Related site guides: use the site's VRR guide and the economics guides in the blog.