Every barrel of reservoir oil carries dissolved gas, and there is a specific pressure at which that gas begins to break out of solution as the first bubble forms. That pressure is the bubble point, and it draws a hard line between two very different kinds of reservoir behavior. This guide defines bubble point pressure, explains the difference between saturated and undersaturated oil, and shows why the pressure at which gas evolves matters for tubing flow, separator staging, and the trends an operator watches on a SCADA screen.
Bubble Point Pressure in one line: Bubble point pressure, also called saturation pressure, is the pressure at which the first bubble of gas comes out of solution from a reservoir oil at reservoir temperature. Above the bubble point the oil holds all of its gas in solution and is called undersaturated; at or below it, gas evolves as a free phase and the oil is saturated. It is one of the most important single numbers a PVT study reports, because so much of a well's behavior changes as pressure crosses it.
Reservoir oil is a mixture of hydrocarbons that, at high reservoir pressure, holds a large amount of lighter components such as methane fully dissolved in the liquid. As pressure falls, the liquid can hold less and less of that gas, and the bubble point is the exact pressure at which the oil becomes saturated - the point where the very first bubble of free gas appears. At any pressure above this value the oil is a single liquid phase carrying all its gas in solution, and at any pressure below it the system splits into oil plus a growing volume of free gas.
The bubble point is measured at reservoir temperature, because both temperature and composition control it. A light oil rich in dissolved gas has a high bubble point, sometimes close to its original reservoir pressure, while a heavier, gas-poor oil may have a bubble point far below reservoir pressure. This is why the same number cannot be assumed from one field to the next: it is a property of the specific fluid, determined in the laboratory from a representative sample rather than estimated from surface readings alone.
Crossing the bubble point is not a subtle event for the reservoir. Once free gas appears in the pore space, the relative permeability to oil drops, the oil left behind shrinks and grows more viscous as it loses light ends, and the solution gas-oil ratio begins to fall. The whole character of production shifts, which is why reservoir engineers treat the bubble point as a threshold rather than just another data point on a curve.
An undersaturated reservoir sits at an initial pressure above the bubble point, so the oil in place is entirely liquid and no free gas cap exists in equilibrium with it. As such a reservoir is produced, pressure declines but stays above the bubble point for a while, and during this phase the drive comes from the slight expansion of the rock and fluids. Recovery in this window is modest because liquids and rock are only weakly compressible, and the oil produced arrives at surface having released its gas only in the tubing and separators, not in the reservoir.
A saturated reservoir sits at or below its bubble point, meaning free gas is already present in the pore space, often as a gas cap above the oil. Here the dominant recovery mechanism becomes solution gas drive: as pressure falls further, gas expands and pushes oil toward the wellbore, but that same free gas competes with oil for flow paths and is eventually produced preferentially. The producing gas-oil ratio typically climbs sharply once the reservoir goes below bubble point, a signature that engineers recognize immediately.
The practical consequence is that the bubble point sets expectations for how a field will behave over its life. An undersaturated oil can be produced efficiently for a time with pressure well above saturation, but planning has to account for the day the reservoir crosses its bubble point, when gas breaks out in the reservoir and the production profile changes. Knowing where that line sits is essential for forecasting rates, sizing surface facilities, and deciding whether pressure maintenance by injection is worthwhile.
The bubble point matters far beyond the reservoir because gas breakout also occurs in the wellbore whenever flowing pressure drops below saturation as fluid rises. When flowing tubing pressure falls below the bubble point, gas comes out of solution inside the tubing, the fluid column becomes lighter and more compressible, and flow can become unstable or begin to slug. This is one reason separator staging is designed the way it is: dropping pressure in stages lets gas evolve in a controlled fashion and stabilizes each cut of liquid before the next, rather than flashing everything at once and losing volatile liquids to the vapor stream.
Field operators rarely measure bubble point directly, but they watch the pressures that reveal a well approaching it. On a cloud SCADA platform such as Merobix, live flowing tubing pressure, casing pressure, and separator pressures are trended continuously, and a well drifting toward its bubble point often shows a rising gas-oil ratio, growing pressure oscillation, or an increasingly noisy flowing pressure signal as gas begins to break out in the tubing. Seeing those trends side by side against a known saturation pressure lets an operator recognize the transition early rather than after a well has started heading and gas-locking.
Because Merobix reads pressures and rates from field devices over protocols such as Modbus and DNP3 and stores the history in the cloud, the changing behavior around bubble point becomes visible as a pattern over weeks and months, not just a single instantaneous reading. That longer view is what turns a raw pressure tag into an early warning: an engineer can overlay flowing pressure against the fluid's bubble point and separator settings and see exactly when a well is moving from stable undersaturated flow into two-phase behavior, and adjust choke or lift accordingly.
Reservoir pressure is the actual pressure in the reservoir at a given time, which declines as the field is produced. Bubble point pressure is a fixed fluid property - the pressure at which gas first evolves from the oil at reservoir temperature. A reservoir is undersaturated when its pressure is above the bubble point and saturated when its pressure reaches or falls below it.
Because it is the pressure at which the oil becomes saturated with dissolved gas and can hold no more. At any higher pressure the oil is undersaturated and holds all its gas in solution; at the saturation pressure the very first free gas bubble appears. The two terms describe the same value from slightly different angles.
It is measured in a PVT laboratory from a representative reservoir fluid sample, typically during a constant composition expansion test. The sample is held at reservoir temperature and pressure is lowered step by step while volume is recorded; the pressure at which the volume-versus-pressure trend changes slope, marking the appearance of free gas, is the bubble point.
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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