tubing head, Oil & Gas Glossary

A tubing head is the wellhead spool that sits above the casing head, supports the tubing hanger, and provides the top connection onto which the Christmas tree is bolted. It is the component that transitions a well from the casing program to the production string, carrying the full weight of the tubing through the hanger, sealing the tubing-by-casing annulus, and giving controlled access to that annulus through side outlets. In a conventional Western Canadian Sedimentary Basin land well the wellhead is a stack of flanged spools: the casing-head housing lands on the surface casing and hangs the intermediate or production casing, the tubing head bolts on top of the casing head and lands the tubing, and the Christmas tree bolts on top of the tubing head to control flow. The tubing head performs several jobs at once. Its internal bowl or profile receives the tubing hanger, which suspends the production tubing string and is set once the tubing is landed at the correct depth after the packer is set or the tubing is spaced out. The hanger seals against the tubing head bore, isolating the produced fluids in the tubing from the annulus between the tubing OD and the production casing ID. The tubing head's two side outlets, fitted with valves, give access to that annulus for monitoring casing pressure, bleeding off gas, injecting corrosion inhibitor or methanol for hydrate control, or circulating kill fluid during a workover. The upper flange of the tubing head is machined to a specific API 6A size and pressure rating, and it must match the bottom connection of the Christmas tree and the tubing hanger neck so the whole assembly makes a pressure-tight, load-bearing stack. In the WCSB the tubing head, like the rest of the wellhead, is manufactured and rated under API Specification 6A, with pressure classes such as 2,000, 3,000, 5,000, and 10,000 psi (roughly 13.8, 20.7, 34.5, and 69.0 MPa) selected to exceed the maximum anticipated shut-in wellhead pressure. Sour service wells in the Alberta Foothills or deep Nisku gas require materials compliant with NACE MR0175/ISO 15156 because hydrogen sulphide at the tubing head can cause sulphide stress cracking of the body, hanger, and seals. Every tubing head installation is pressure-tested and its outlet valves and hanger seals verified before the tree goes on, because it is the last barrier between annulus pressure and the surface, and a leak here is both a safety hazard under AER Directive 037 and a source of surface-casing-vent-flow reporting obligations.

Key Takeaways

It lands and seals the tubing string: The tubing head's internal bowl receives the tubing hanger, which suspends the full weight of the production tubing and seals the tubing-by-casing annulus. This transfers the tubing load into the wellhead stack and isolates produced fluid in the tubing from the outer annulus, the boundary that lets an operator monitor and control annulus pressure independently of production.
It carries the Christmas tree: The tubing head's top flange is the mounting face for the Christmas tree. The flange size, ring-groove, and API 6A pressure rating must match both the tree below-connection and the tubing hanger neck, so the head is the mechanical hinge between the casing program and the surface production controls in a WCSB completion.
Side outlets give annulus access: Two valved outlets on the tubing head open the tubing-by-casing annulus to surface for pressure monitoring, gas bleed-off, chemical injection of methanol or corrosion inhibitor, and kill-fluid circulation during workovers. This annulus access is essential for hydrate management on WCSB gas wells and for detecting tubing or packer leaks early.
API 6A rating must exceed shut-in pressure: Tubing heads are built and pressure-classed under API 6A at ratings such as 3,000, 5,000, and 10,000 psi (20.7, 34.5, 69.0 MPa). The selected class must exceed the maximum anticipated shut-in wellhead pressure with margin, and the whole stack is pressure-tested before the tree is installed and the well brought on.
Sour service demands NACE-compliant metallurgy: On WCSB sour wells, H2S at the wellhead can cause sulphide stress cracking, so the tubing head body, hanger, and elastomeric seals must meet NACE MR0175/ISO 15156. Material selection, hardness limits, and seal compatibility are verified during procurement because a cracked tubing head on a sour well is a serious safety and regulatory failure under AER Directive 037 and Directive 056.

Tubing Hanger Types and Setting

The tubing hanger landed in the tubing head comes in two broad styles: a mandrel-type hanger that threads onto the top of the tubing and lands in the head bowl, common where the tubing is spaced out precisely, and a wrap-around or boll-weevil style used on simpler WCSB pumping wells. Once the tubing is at depth and the packer set, the hanger is landed, energized, and lock-down screws or a lock ring secure it against tubing pressure trying to push it up. The hanger seal is then tested from below through the tubing and from above before the tree is nippled up, confirming both the tubing hang and the annulus isolation are sound.

Annulus Monitoring and Surface Casing Vent Flow

The tubing head side outlets are where a WCSB operator watches the tubing-by-production-casing annulus, but the outer annuli are monitored at the casing head below. Pressure building on the tubing head annulus outlet can indicate a tubing leak, a packer leak, or a failed hanger seal, and it must be investigated rather than simply bled off. Because AER Directive 020 and surface casing vent flow rules require reporting and remediation of certain annular pressures and flows, the tubing head outlets are a routine part of well integrity surveillance across the basin, not just a convenience during workovers.

Fast Facts

The flanged, bolt-together wellhead stack that puts the tubing head between the casing head and the Christmas tree is a direct descendant of the spooled wellheads standardized in the 1920s and 1930s, and the API 6A ring-joint flange it uses is the same basic pressure seal, a soft metal ring compressed in machined grooves, found on subsea trees in 2,000 m of water off Canada's East Coast. A tubing head bolted up on a shallow Lloydminster heavy-oil well shares its sealing principle with the highest-pressure deepwater completions in the world.

The tubing head sits directly between the casing head below it and the Christmas tree above it, forming the middle of the wellhead stack. It exists to land and seal the tubing string via the tubing hanger, and its side outlets open the annulus between tubing and casing for monitoring and chemical injection. Each connection is a load-bearing, pressure-sealing interface rated under a common API 6A specification.

Real-World WCSB Scenario: An Annulus Leak on a Sour Nisku Gas Well

An operator in west-central Alberta ran a sour Nisku gas completion with a tubing head rated to 10,000 psi (69.0 MPa) in NACE-compliant material. Six months after start-up, the tubing head annulus outlet began building pressure to about 4,200 kPa between weekly checks. Rather than simply bleed it down, the operator ran a diagnostic, isolating the tree and pressure-testing the tubing, and found the hanger seal had extruded slightly, allowing tubing gas containing H2S to communicate into the annulus. A workover to pull the tree, replace the hanger seal assembly, and re-test cost roughly CAD 210,000 including a service rig, sour-service crew, and lost production.

Because the leak was caught early through routine tubing head annulus monitoring, it never became a surface release or a reportable vent flow under AER Directive 020. The operator credited the two valved outlets and a disciplined weekly pressure log for turning what could have been an uncontrolled sour-gas incident into a planned, contained repair.