Tubing Performance (VLP) & Multiphase Correlations
Fluid has reached the wellbore - now it must climb the tubing to surface. The vertical lift performance curve tells you the bottomhole pressure needed to lift a given rate, and in multiphase flow that curve bends into a characteristic J-shape.
Fluid has reached the wellbore - now it must climb the tubing to surface, and the pressure needed to lift it bends into a tell-tale J-shape.
What the VLP Is
Fluid arriving at the wellbore is only halfway home - it still has to climb the tubing from bottomhole up to the surface. The vertical lift performance (VLP) curve, also called the tubing intake or outflow curve, answers a single question: what bottomhole pressure is required to push a given liquid rate all the way up the tubing to surface? That required pressure has three parts, $p_{wf,\text{required}} = p_{wh} + \text{hydrostatic (gravity) head} + \text{friction losses}$, where $p_{wh}$ is the wellhead (surface) pressure, the hydrostatic head is the weight of the fluid column the well must lift against gravity, and the friction losses are the drag of the fluid against the tubing wall. The VLP is the demand side of the producing system - the pressure the well must be supplied with to deliver a chosen rate.
Why the VLP Curve Is J-Shaped
For a single-phase liquid, the VLP simply rises with rate as friction grows. But most producing wells flow multiphase fluid - oil, water, and gas together - and that changes everything, because the fluid density and the liquid holdup (the fraction of the tubing filled by liquid) themselves depend on rate. At low rate, gas bubbles through the liquid sluggishly, the column stays heavy with liquid, and the gravity/holdup term dominates - so a surprisingly high bottomhole pressure is needed to lift even a small rate, giving an unstable left branch. At high rate, the fluid whips up the tubing and friction dominates, so the required pressure climbs again. Between the two extremes the curve dips to a minimum - the rate where the well lifts most efficiently. That low-then-high behaviour traces a characteristic J-shape on a pressure-versus-rate plot.
Computing that J-shaped curve for real multiphase flow is hard, because the gas slips past the liquid and the flow regime changes along the tubing. Engineers do not solve it from first principles on the job - they use semi-empirical multiphase pressure-traverse correlations, each fitted to laboratory and field data to predict the pressure profile from bottomhole to surface. Three are household names: Hagedorn-Brown (developed for vertical oil wells), Duns-Ros (covering a wide range of gas and liquid rates and flow regimes), and Beggs-Brill (originally for inclined and directional flow). The details differ, but the job is the same - take a rate, a fluid property set, and a tubing geometry, and return the pressure drop up the string. The next lesson pairs one such VLP curve with the reservoir's inflow curve and finds where they meet.
Check your understanding
- Vertical lift performance (VLP) is the bottomhole pressure required to lift a given rate up the tubing to surface: p_wf,required = p_wh + hydrostatic head + friction losses - the demand side of the producing system.
- In multiphase flow the VLP curve is J-shaped: gravity/liquid holdup dominates at low rate (high required pressure, unstable left branch) and friction dominates at high rate, with an efficient minimum in between.
- Multiphase pressure-traverse correlations - Hagedorn-Brown, Duns-Ros, Beggs-Brill - predict the pressure profile up the tubing from rate, fluid properties, and tubing geometry.