Getting fluid out of a reservoir is only half the problem; the other half is lifting it up the tubing to surface, and the tubing performance curve describes exactly how hard that is. Also called the vertical lift performance or VLP curve, it is the outflow side of nodal analysis and it answers a single question at every possible flow rate: how much bottomhole pressure does the well need to push that rate up the tubing against gravity and friction? This guide explains what the curve represents, why it often has a distinctive U shape, and how it interacts with liquid loading and the decision to add artificial lift.
Tubing Performance Curve (VLP) in one line: A tubing performance curve, or VLP curve, plots the bottomhole flowing pressure a well must supply against the production rate it can lift to surface through the tubing. It is the outflow half of nodal analysis: for each rate it sums the hydrostatic weight of the fluid column and the friction of pushing fluid up the pipe to give the required intake pressure. Where the tubing curve crosses the inflow performance curve is the rate and pressure at which the well will actually flow.
The tubing performance curve treats the wellbore as a pressure-loss problem. To flow a given rate to surface, the bottomhole pressure has to overcome three things: the surface pressure the fluid is being delivered against, the hydrostatic head of the fluid column standing in the tubing, and the frictional pressure drop of moving fluid up the pipe. The curve is the sum of those contributions expressed as required bottomhole flowing pressure at each rate, so a point high on the curve means the well needs a lot of downhole pressure to sustain that rate, and a point low on the curve means it needs less.
The shape is what makes the curve interesting, and in wells producing gas or a mix of oil, gas, and water it is often U shaped rather than a simple line. At low rates the velocity in the tubing is too weak to carry liquids efficiently, so liquid accumulates, the fluid column gets heavier, and the hydrostatic term dominates, driving the required pressure up on the left side of the U. At high rates the friction term takes over and drives the required pressure up on the right side. Between those extremes sits a minimum, and that minimum is deeply significant because the whole left branch of the curve is the region where a well is prone to instability and liquid loading.
Because the hydrostatic and friction terms depend on how gas and liquid distribute themselves in the pipe, calculating a VLP curve is a multiphase flow problem rather than a simple pipe-loss calculation. Engineers use multiphase flow correlations to predict the pressure gradient at each rate, then repeat the calculation across a range of rates to trace the full curve. Change the tubing size, the water cut, the gas-liquid ratio, or the wellhead pressure, and the whole curve shifts, which is exactly what makes it a design tool.
The tubing performance curve is only half of nodal analysis. Its partner is the inflow performance curve, which describes what the reservoir can deliver into the wellbore: the higher the drawdown, the lower the bottomhole pressure, and the more the reservoir pushes out. The inflow curve slopes down as rate increases because higher rates require lower flowing bottomhole pressure, while the outflow VLP curve behaves according to its U shape. Both are plotted as bottomhole pressure against rate on the same axes.
Where the two curves intersect is the operating point of the well, the natural equilibrium rate and pressure at which the reservoir supplies exactly the fluid the tubing can lift. This crossing point is the single most useful output of nodal analysis, because it predicts what a well will actually produce rather than what the reservoir could deliver in isolation. If an engineer wants more production, the curves show whether the constraint is inflow, meaning the reservoir, or outflow, meaning the lift up the tubing, and that tells them where intervention will pay off.
The interaction also warns of trouble. If the reservoir pressure falls or the water cut rises over time, the inflow curve shrinks and can end up intersecting the VLP curve on its unstable left branch, or fail to intersect a stable point at all. That situation means the well no longer has the energy to lift its own liquids reliably, and it is the analytical fingerprint of a well heading toward liquid loading. Nodal analysis lets an engineer see that coming before the well dies and plan the response.
The tubing performance curve is where the choice of artificial lift gets made. Each lift method reshapes the outflow side in a different way. Installing a smaller tubing string raises velocity and can keep a marginal gas well on the stable branch of the curve. Gas lift injects gas to lighten the fluid column and pull the hydrostatic term down. A downhole pump adds pressure directly, effectively shifting the whole required-pressure curve so the reservoir can once again meet it. Engineers compare candidate methods by seeing which one moves the operating point back into a stable, productive region.
None of this is a one-time calculation, because the curves drift as the well ages. Reservoir pressure declines, water cut climbs, and gas-liquid ratio changes, so a VLP and inflow analysis that was valid at first flow can be badly out of date a year later. That is why the analysis is most powerful when it is refreshed against real production data rather than left as a commissioning study. The measured flowing wellhead pressure, rate, and casing pressure a well reports every day are exactly the inputs needed to keep the curves current.
A cloud SCADA platform such as Merobix is what supplies that continuous stream. By reading tubing and casing pressures, meter rates, and separator data from field devices over protocols like Modbus and MQTT and storing them as trended history, it lets an engineer watch the real operating point migrate over time. When the trend shows flowing pressure creeping toward the unstable branch of the tubing curve, that is early warning that the well is approaching liquid loading, and it turns nodal analysis from a static design exercise into a living diagnosis that flags when it is time to change tubing, add lift, or start a plunger.
IPR, the inflow performance relationship, describes what the reservoir can deliver into the wellbore at each bottomhole pressure, so it is the inflow side of the well. VLP, the vertical lift performance or tubing performance curve, describes the bottomhole pressure the well needs to lift each rate up the tubing to surface, so it is the outflow side. Nodal analysis plots both together and their intersection is the well's operating rate.
The U shape comes from two competing pressure losses. At low rates the tubing velocity is too weak to carry liquids, so the fluid column loads up and gets heavy, driving the required pressure up on the left. At high rates friction dominates and drives the required pressure up on the right. The minimum between them is the most efficient rate, and the left branch is where liquid loading and unstable flow occur.
Liquid loading happens on the unstable left branch of the tubing curve, where gas velocity is too low to lift liquids and the column becomes heavy. If declining reservoir pressure pushes the well's operating point onto that branch, the well can no longer reliably carry its own liquids and starts to load up. Watching the operating point move toward that branch on live data is an early warning that intervention such as smaller tubing, plunger lift, or gas lift is needed.
This page references the protocol specifications published by the organizations below. Editions, product capabilities, and documentation change over time - confirm current requirements and specifications directly with the source.
Last reviewed: July 27, 2026. Merobix is not affiliated with, endorsed by, or sponsored by these organizations; their names are used only to identify the standards and products discussed.
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