Production tubing is the pipe that actually carries oil and gas to the surface - a slender string run inside the casing once a well is ready to produce. Unlike casing, it is not cemented in place and can be pulled and replaced during a workover. This guide explains what production tubing is, why produced fluids travel up tubing rather than the casing, and how tubing pressure is used to watch a well.
Production Tubing in one line: Production tubing is the string of pipe run inside a well's production casing to carry produced oil, gas, or water from the reservoir up to the wellhead. It is smaller than casing, is not cemented, and can be retrieved and replaced, making it the removable flow conduit of a producing well.
Once a well is completed, produced fluids are directed up the tubing rather than the wide casing annulus for good reasons. A smaller conduit keeps flow velocity high enough to lift liquids to surface instead of letting them fall back and load up the well. It concentrates flow in a replaceable pipe, protecting the expensive cemented casing from erosion, corrosion, and scale. And it isolates the produced stream so the annulus can be sealed off and monitored separately.
A packer usually seals the space between the tubing and casing just above the reservoir, forcing all production into the tubing and creating a protected annulus above it. This is why the tubing-casing annulus can be pressure-monitored as a separate integrity signal while production runs up the tubing string beneath it.
Tubing is made up of threaded joints, typically around 30 feet each, screwed together into a string that reaches from the wellhead down to near the producing zone. It hangs from a tubing hanger in the wellhead and is often anchored or set on a packer downhole. Artificial-lift equipment lives on or in the tubing: a rod pump's plunger travels inside it, an electric submersible pump is run on the bottom of it, and gas-lift valves sit in side pockets along it.
Because tubing is retrievable, it is the part of the well most often serviced. A workover rig can pull the tubing to replace a failed pump, change out corroded joints, or reconfigure the completion, then run it back in - something impossible with cemented casing.
Flowing tubing pressure - measured at the wellhead where the tubing terminates - is one of the primary indicators of how a well is producing. A drop can signal declining reservoir energy or a lift problem; a rise can indicate a restriction downstream. Operators trend tubing pressure against casing pressure and flow to diagnose well behavior from surface. That measurement is taken by a pressure transmitter on the tubing head and digitized into a tag by a wellsite RTU or flow computer. A cloud SCADA such as Merobix reads that tubing pressure tag over Modbus or DNP3, so an operator can watch flowing tubing pressure across a whole field and set alarms when a well drifts outside its normal band.
It carries produced oil, gas, and water from the reservoir up to the wellhead. Running fluids up a smaller, replaceable string keeps flow velocity high enough to lift liquids, protects the cemented casing from erosion and corrosion, and isolates the produced stream so the annulus can be sealed and monitored separately.
Casing is the larger pipe cemented permanently into the wellbore to line and seal the hole. Tubing is the smaller pipe run inside the production casing to carry fluids to surface, and unlike casing it is not cemented and can be pulled and replaced during a workover. Casing is structural; tubing is the removable production conduit.
It is the pressure measured at the wellhead in the tubing while the well is producing. It is a key diagnostic: a declining trend can indicate falling reservoir energy or a lift problem, while a rise can point to a downstream restriction. Operators monitor it alongside casing pressure and flow rate through SCADA.
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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