Tubing, Oil & Gas Glossary

What Is Production Tubing?

Production tubing is the small-diameter steel pipe string run inside the casing of a producing oil or gas well that serves as the primary conduit for reservoir fluids — oil, gas, and water — from the producing interval to the surface wellhead, and is designed to API 5CT or equivalent international standards with wall thickness, grade, and connection type selected to withstand the full range of burst, collapse, tension, compression, and corrosion loads across the well's producing life from initial high-rate flow through artificial lift and eventual abandonment.

Key Takeaways

Tubing is run inside the production casing and landed on or above the perforations, seated in a packer that isolates the tubing-casing annulus from producing intervals — directing produced fluids up the tubing bore and providing an annular gas lift or chemical injection pathway if needed.
Common production tubing outside diameters (OD) are 60.3 mm (2⅜ in.), 73 mm (2⅞ in.), 88.9 mm (3½ in.), and 114.3 mm (4½ in.) — with size selected based on production rate, artificial lift method, and whether wireline tools must be run inside the tubing for well interventions.
Tubing material grade is specified to API 5CT: J-55, K-55, and N-80 for conventional low-corrosion wells; L-80, C-90, and P-110 for higher-strength applications; and CRA (Corrosion Resistant Alloy) grades such as 13Cr, 22Cr, or 25Cr duplex stainless for sour wells with H2S and CO₂, in compliance with NACE MR0175/ISO 15156.
Tubing connections range from API threaded-and-coupled (BTC/LTC/STC) for standard applications to premium connections (VAM, Tenaris TenarisHydril, Grant Prideco) for HPHT, sour service, and wells requiring gas-tight sealing — connection selection is a critical part of tubing design because connection failure is the primary cause of tubing string leaks and well integrity events.
Tubing design is governed by ISO 10400 (Petroleum and Natural Gas Industries — Formulae and Calculation for Casing, Tubing, Drill Pipe and Line Pipe Properties) and API 5C3 for strength calculations, with well-specific design loads developed using pressure-temperature modelling of producing and shut-in conditions across the entire well life.

How Production Tubing Works

When a well is completed, production tubing is run from surface into the wellbore on the end of a tubing string — individual joints of 9.1 to 9.6 m (30 to 32 ft) length made up sequentially from the rig floor as the string is lowered. At the bottom of the string, a production packer is set in the casing above the perforations: the packer's slips and seal element expand to grip the casing wall and isolate the tubing-casing annulus, preventing high-pressure reservoir fluids from bypassing the tubing and acting on the surface casing or wellhead at full reservoir pressure.

Produced fluids enter the perforations, flow through the completion interval, pass up the tubing bore, and exit at the wellhead through the production wing valve of the Christmas tree. The tubing bore must be sized to avoid excessive flow velocity (which causes erosion of connections and downhole tools) and insufficient velocity (which allows fluid slugging and liquid loading in gas wells). For artificial lift — gas lift, ESP, rod pump — the tubing provides the conduit for both lift gas injection (gas lift) or the pump intake and discharge path (ESP, rod pump).

Tubing Design and Standards Across International Jurisdictions

In Canada, production tubing specifications for Alberta wells are governed by AER Directive 010 (Minimum Casing Design Requirements) and AER Directive 036, which reference API 5CT and NACE MR0175/ISO 15156 for sour service. In the Montney play, H2S partial pressures above 0.0003 MPa (0.05 psi) trigger sour service material requirements, meaning most Montney wells require at minimum L-80 or C-90 grade tubing with premium connections rather than standard J-55 or N-80. Oil sands SAGD wells present extreme thermal loading: steam injection temperatures of 220 to 240°C (428 to 464°F) and cyclic thermal cycles require high-chrome steel grades and metal-to-metal seal premium connections that maintain gas-tight seals under thermal expansion and contraction.

In the United States, API 5CT is the governing standard for tubing design; BSEE requires well design documentation including tubing specifications for all OCS wells. Deepwater Gulf of Mexico wells face extreme design challenges — high-pressure reservoirs at 69 to 138 MPa (10,000 to 20,000 psi), CO₂-rich fluids requiring 13Cr or 22Cr CRA grades, and subsea wellhead thermal cycling that imposes complex combined loading on tubing connections. In Norway, Sodir's well integrity regulations and NORSOK D-010 (Well Integrity in Drilling and Well Operations) specify tubing design requirements and well integrity verification for all NCS wells; Equinor, Aker BP, and Vår Energi conduct annual well integrity status reviews covering tubing condition across their NCS well inventories. In Australia, NOPSEMA's well integrity requirements under the Offshore Petroleum and Greenhouse Gas Storage Act mandate tubing design verification and periodic annular pressure monitoring to confirm tubing string integrity in all producing offshore wells. In the Middle East, Saudi Aramco's SAES-L-034 and related engineering standards govern tubing design for Ghawar, Safaniya, and offshore fields; the high H2S and CO₂ environment in sour gas wells at Haradh and Hawiyah requires 13Cr and duplex stainless steel tubing with premium connections qualified to NACE MR0175.

Fast Facts

The total length of production tubing in active oil and gas wells worldwide exceeds 10 million kilometres (6.2 million miles) — enough to wrap around the Earth more than 250 times. Every joint of that tubing was inspected, made up to a specified torque, and pressure-tested before being released for service, because a single tubing connection failure in a sour well can cause an uncontrolled H2S release that evacuates a facility and triggers a well integrity emergency response.

Tubing Failure Modes and Well Integrity

The primary tubing failure modes in oil and gas wells are: connection leaks (inadequate makeup torque, damaged thread, or loss of sealing contact under thermal cycling or combined loading); corrosion pitting and wall-thickness loss from CO₂ (sweet corrosion), H2S (sulphide stress cracking), or oxygen-contaminated injection water; mechanical failure from over-pull during stuck-pipe situations or excess compression under thermal growth; and erosion of tubing body and connections from sand production or high-velocity gas flow. Well integrity management — the systematic programme of annular pressure monitoring, periodic tubing inspection during workovers, and corrosion inhibitor injection — is required by all major regulators and is one of the primary operational responsibilities of producing well operators. NORSOK D-010 and API RP 90 provide the framework for ongoing well integrity management programmes in Norway, the US, and internationally.

Tip: When running production tubing in a well with CO₂ partial pressure above 0.03 MPa (4.4 psi) — the NACE MR0175 sweet corrosion threshold — specify corrosion-resistant alloy (CRA) grade tubing (13Cr minimum) even if H2S is below the sour service threshold. CO₂ corrosion in standard carbon steel tubing with produced water can perforate a 7.1 mm (0.28 in.) wall tubing in 3 to 5 years at moderate CO₂ levels, requiring an expensive tubing workover that costs more than the CRA upgrade would have. Carbon steel with corrosion inhibitor injection is an alternative, but requires rigorous chemical treatment and monitoring programmes that must be maintained for the entire well life.

Production tubing is also known as:

Tubing string — the full assembled string of tubing joints run in the wellbore; used in well programme documentation and completion engineering reports
Production string — the complete completion assembly including tubing, packer, downhole safety valve, and artificial lift equipment; used in well design documentation
OCTG — Oil Country Tubular Goods; the broader product category that includes casing, tubing, and drill pipe manufactured to API 5CT and 5DP; used in procurement and materials management
Completion tubing — used in some contexts to describe tubing run as part of a completion (as opposed to workover tubing run temporarily for intervention work)

Related terms: casing, packer, Christmas tree, gas lift, H2S, well control

Frequently Asked Questions

What is the difference between casing and tubing?

Casing is large-diameter pipe permanently cemented in the wellbore during drilling to provide structural integrity, isolate formations, and protect groundwater. Production tubing is smaller-diameter pipe run inside the casing after completion that serves as the producing conduit. Casing stays in the well permanently; tubing can be pulled out and replaced during a workover. Produced fluids travel up the tubing bore; the tubing-casing annulus is isolated by the packer and monitored for pressure as a well integrity indicator.

How is tubing size selected?

Tubing size is selected based on the anticipated production rate (sufficient bore area to carry expected fluid volumes without excessive velocity or liquid loading), the artificial lift method (rod pump requires tubing sized for the pump barrel OD plus clearance; ESP requires minimum ID to run the pump motor), and the need to run wireline tools for future intervention (tubing ID must exceed the largest tool OD to be used). Nodal analysis modelling — which calculates the tubing intake and wellhead pressure relationship at various flow rates — is the engineering method used to optimise tubing size for each well.

What grade of tubing is required for sour service?

For wells with H2S partial pressure above 0.0003 MPa (0.05 psi) — the NACE MR0175/ISO 15156 threshold — sour service tubing grades are required to prevent sulphide stress cracking. Acceptable grades include L-80 Type 1, C-90, T-95, P-110 (with restrictions), and 13Cr CRA for higher H2S environments. J-55 and N-80 standard carbon steel are NOT acceptable for sour service. All sour service tubing must also use connections qualified to NACE MR0175 and must be handled and made up according to manufacturer torque specifications to avoid connection cracking.

Why Production Tubing Matters in Oil and Gas

Production tubing is the wellbore's working pipe — every barrel of oil and every cubic foot of gas produced from every well in the world travels up production tubing. Its design quality directly determines well safety and producing life: correctly designed, properly made up, and maintained with a rigorous well integrity programme, tubing strings perform for 20 to 30 years in some of the most corrosive, high-pressure, and thermally extreme environments in the industrial world. Improperly designed or maintained, tubing failures cause well integrity events — casing annulus pressure anomalies that require intervention, H2S releases in sour fields that trigger emergency response, and well losses that remove producing assets from the inventory. In a mature basin like the WCSB or the North Sea, where thousands of wells are in simultaneous production, the systematic management of tubing integrity is one of the highest-value and highest-consequence operational responsibilities in the upstream business.

Production Tubing: Definition, API Standards, and Well Design