On a gas-lift well, the pressure gauge on the casing side of the wellhead is the single most useful number an engineer has. Casing head pressure, or CHP, is the surface pressure of the injection gas held in the tubing-casing annulus, and its steady value and its day-to-day trend tell you which valve is actually passing gas and whether the well is lifting from the depth it was designed for. This guide explains what CHP is, why its trend matters more than its instantaneous value, and how automation reads it alongside injection rate to keep gas going in at the deepest intended valve.
Casing Head Pressure in one line: Casing head pressure (CHP) is the surface pressure of the injection gas in the annulus of a gas-lift well, measured at the casing outlet on the wellhead. Because each gas-lift valve opens and closes at a characteristic pressure, the CHP a well settles at tells you which valve is passing gas and how deep the point of injection is.
Injection gas is delivered from a surface line into the tubing-casing annulus, travels down that annulus, and enters the tubing through whichever gas-lift valve is open. The casing head pressure is simply the surface pressure of that annulus gas, read at the casing outlet on the wellhead. It reflects the pressure available at surface to push gas down the annulus and through the operating valve, plus the weight of the gas column in the annulus once you correct for depth.
Every gas-lift valve in the mandrel string is set to open and close at a specific pressure, so the annulus behaves almost like a pressure-controlled switch. When the well settles into steady lift, the CHP will hover near the operating pressure of the valve that is currently passing gas. That is why CHP is a diagnostic and not just a supply reading: the value the well chooses to settle at is a fingerprint of which valve is doing the work.
CHP is distinct from tubing pressure, which is the pressure of the produced fluid on the tubing side of the wellhead. The difference between casing and tubing pressure across a valve is what actually drives gas from the annulus into the tubing. Reading both together, rather than CHP alone, is how an analyst separates a supply problem from a downhole valve or reservoir problem.
A healthy gas-lift well that is lifting from the deepest intended valve holds a stable CHP right around that valve's operating pressure. If the CHP creeps upward over days or weeks while injection rate holds, the point of injection has usually moved shallower, meaning a deeper valve has stopped passing and gas is entering through an upper valve at a higher operating pressure. A steadily rising casing pressure trend is one of the clearest early signals that a well is no longer lifting from its design depth.
An erratic, sawtooth CHP trace often means multipointing, where gas is passing through more than one valve at once, or heading, where the well is cycling between loading and unloading. Neither is efficient: gas injected through shallow valves lifts a shorter column and returns less oil per unit of gas. A CHP that falls unexpectedly can point the other way, toward a leaking mandrel, a cut-out valve seat, or a hole in the tubing that lets annulus gas short-circuit into the tubing without doing useful lift work.
Because these signatures are all about how the pressure moves over time, a single manual gauge reading during a route visit rarely catches them. The valuable information lives in the shape of the trend: how fast CHP rises, whether it oscillates, and how it responds when injection rate is nudged. That is exactly the kind of continuously sampled history that field automation is built to capture.
A cloud SCADA platform reads casing head pressure, tubing pressure, and injection gas rate from the wellsite RTU or flow computer and trends all three together. Seeing them on one screen lets an analyst tell at a glance whether a rising CHP is being caused by too much gas going in, a shifted injection point, or a downstream backpressure change. The injection-rate reading is the context that turns a bare pressure number into an actionable diagnosis.
Automation also lets an operator set the target: enough gas to keep the deepest valve open and passing, but not so much that the well starts injecting through shallow valves or heading. A SCADA controller can hold injection rate or annulus pressure to a setpoint through an injection-control valve, and it can alarm when CHP drifts outside the band expected for lift from the design valve, prompting a review before production quietly falls off.
Merobix reads these gas-lift signals into a browser dashboard so the CHP trend, injection rate, and tubing pressure for every well sit side by side and update continuously. Instead of discovering weeks later that a well moved to a shallow injection point, an engineer sees the casing pressure trend climb in near real time and can adjust injection or schedule a valve intervention while the loss is still small.
There is no universal figure; the normal CHP for a given well is roughly the operating pressure of the gas-lift valve it is designed to lift from, which depends on the valve settings, injection-gas supply pressure, and depth. What matters operationally is that the CHP is stable and close to that expected value. A steady CHP near the design operating pressure is normal; a drifting or oscillating one is the warning sign.
The most common reason is that the point of injection has moved shallower: a deeper valve has stopped passing gas, so injection shifts to an upper valve with a higher operating pressure and the annulus settles at a higher CHP. Excess injection gas or a change in downstream backpressure can also raise it. Because a rising CHP usually means lift is no longer coming from the deepest valve, it warrants investigation rather than simply turning gas up.
Casing head pressure is the surface pressure of the injection gas in the annulus, while tubing pressure is the pressure of the produced fluid on the tubing side of the wellhead. Gas flows from the annulus into the tubing because casing pressure exceeds tubing pressure across the open valve. Tracking both, and the difference between them, separates a gas-supply issue from a downhole valve or reservoir problem.
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