Wellhead pressure is the number an operator looks at first - the pressure measured at the top of a well that summarizes, in a single reading, a great deal about how the well is behaving. It is the most accessible window into a producing well and the primary signal that flows into field monitoring. This guide explains what wellhead pressure is, the difference between tubing and casing pressure, and what changes in it reveal.
Wellhead Pressure in one line: Wellhead pressure is the pressure measured at the surface at the top of a well, on the wellhead. It is most often reported as flowing tubing pressure - the pressure in the production tubing while the well flows - plus casing pressure in the annulus. Together they are the primary surface indicators of a well's production and integrity.
Wellhead pressure is not a single value but a small set of related pressures. Flowing tubing pressure (FTP) is measured in the production tubing while the well flows and reflects the well's productivity and any downstream restriction. Casing pressure is measured in the tubing-casing annulus and, for a well with a packer, should be stable - a change is a classic integrity warning. In gas-lift wells the casing pressure is an active operating parameter rather than just an integrity check.
Shut-in tubing pressure is what the wellhead reads after the well has been closed in and pressures have built up and stabilized. Because no fluid is moving, shut-in pressure reflects the reservoir's stored energy transmitted to surface, so it is a stronger indicator of reservoir condition than flowing pressure. Operators compare flowing and shut-in pressures to understand how hard the reservoir is pushing.
Trends in wellhead pressure are among the most useful diagnostics an operator has. A gradual decline in flowing tubing pressure over months tracks the natural depletion of the reservoir. A sudden drop can mean a lift failure, a hole in the tubing, or a line problem, while an unexpected rise can indicate a downstream blockage or a closed valve. A divergence between tubing and casing pressure points toward a leak or a packer issue.
Because these signals are so informative and available right at the surface, wellhead pressure is the backbone of routine well surveillance. High and low pressure limits are set as alarms so an operator is notified when a well steps outside its normal operating band, often before a problem becomes a failure or a spill.
Wellhead pressure is measured by pressure transmitters mounted on the tubing head and casing outlet. Their signals are wired into a wellsite RTU or flow computer, which digitizes each into a tag such as WH_TUBING_PRESS and WH_CASING_PRESS. The controller then serves those tags to SCADA over an industrial protocol for display, trending, and alarming. A cloud SCADA such as Merobix reads those wellhead pressure tags from the RTU or flow computer over Modbus, DNP3, or OPC UA and presents them in a browser. That gives operators a live, field-wide view of tubing and casing pressure on every well, with alarms on high and low limits, so a pressure excursion on a remote well is seen immediately instead of at the next site visit.
Wellhead pressure is the pressure measured at the surface on the top of a well. It is usually reported as flowing tubing pressure in the production tubing and casing pressure in the annulus. Together these are the primary surface indicators of how a well is producing and whether its integrity is intact.
Tubing pressure is measured in the production tubing that carries fluids to surface and reflects the well's productivity and downstream conditions. Casing pressure is measured in the tubing-casing annulus and, in a well with a packer, should stay stable - a change usually signals a leak or integrity problem. In gas-lift wells, casing pressure is an active operating parameter.
Shut-in wellhead pressure is the pressure read at the wellhead after the well has been closed in and pressures have built up and stabilized. With no fluid flowing, it reflects the reservoir's stored energy transmitted to surface, making it a stronger indicator of reservoir condition than flowing pressure. It is compared with flowing pressure in well analysis.
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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