Demo Tool · Well Performance

Where the reservoir meets the tubing.

Nodal analysis finds the one rate a well will actually flow — the point where the reservoir's ability to push fluid in (inflow) balances the tubing's ability to lift it out (outflow). Move a slider and watch the operating point chase the new equilibrium in real time.

Composite Darcy + Vogel inflow, two-phase tubing lift

Inflow / Outflow — Operating Point

IPR (inflow) VLP (outflow) Operating point
Operating Rate
—bopd
Flowing BHP
—psia
Absolute Open Flow
—bopd
Drawdown
—psi
Adjust a parameter to see how the operating point responds.
↑ Bigger tubing
↓ Lower wellhead pressure
✦ Stimulate (remove skin)
↓ Depleted reservoir

Production Sensitivity — Drawdown × Skin

Each cell is the inflow rate the reservoir delivers at that combination of drawdown (ΔP) and skin. Read left-to-right to see the prize from pulling the well harder; read top-to-bottom to see the prize from stimulation. The diagonal toward the bottom-right is where both levers compound.

Rate low high

The physics. Oil inflow uses a composite model — straight-line productivity index above the bubble point, q = J(P̄ − Pwf), transitioning to Vogel's two-phase relation q/qmax = 1 − 0.2(Pwf/Pb) − 0.8(Pwf/Pb)² below it. Gas inflow uses the backpressure deliverability equation q = C(P̄² − Pwf²)n. The outflow (VLP) curve sums a hydrostatic head — lightened by produced gas — and a friction term that grows with the square of rate and falls steeply with tubing diameter, reproducing the characteristic J-shape and its low-rate liquid-loading hook. The operating point is the numerical intersection. Figures are illustrative and tuned for responsiveness, not a substitute for a calibrated PVT and multiphase-correlation model.