Tubing Job: Production Tubing Replacement, Workover Rigs, and Well Integrity Restoration

A tubing job is the operation of pulling and replacing the production tubing string in an oil or gas well, almost always carried out as part of a major workover after the well has been killed and a service rig moved onto location. Production tubing is the inner conduit, typically 2 3/8, 2 7/8, or 3 1/2 inch outside diameter in WCSB wells, that carries reservoir fluids from the producing zone to surface inside the larger production casing. Over a well's life that tubing corrodes, scales up, splits at a coupling, or suffers thread leaks and erosion, any of which can threaten well integrity, choke production, or let pressure communicate into the casing annulus. When that happens the operator schedules a tubing job: kill the well with a controlled-density fluid so it will not flow during the operation, rig up a workover rig, unseat the production packer, and trip the entire tubing string out of the hole joint by joint, inspecting, replacing, or re-running each section before setting a new packer and returning the well to production. The term is used specifically when the full tubing string is removed and replaced, which distinguishes it from lighter through-tubing services such as coiled tubing, slickline, or wireline work that treat or clean a well without pulling the completion. A full tubing job is one of the more involved and costly categories of well servicing because it requires well control, a rig with adequate hook load, pipe handling, and often replacement of downhole components such as the packer, gas-lift mandrels, subsurface safety valve, or pump assembly while the string is out. In Alberta the work falls under AER Directive 037 for service rig operations and the well integrity expectations of Directive 087, and it must be planned around proper kill-fluid design, blowout preventer rig-up, and barrier verification so that pulling the tubing never exposes the formation to an uncontrolled flow path. Operators weigh a tubing job against alternatives constantly: if the problem can be fixed through the existing tubing, a cheaper through-tubing intervention is preferred, but if the tubing itself is the failed component, or if a major recompletion to a new zone is planned, pulling and replacing the string is unavoidable. The decision is fundamentally economic, balancing the cost and deferred production of the rig time against the value of restored or improved flow and the regulatory necessity of maintaining mechanical integrity.

Killing the Well and Tripping the String

Every tubing job starts with well control. The crew circulates a kill fluid, usually a calcium chloride or calcium bromide brine weighted to overbalance reservoir pressure, until the well is static and will not flow. With BOPs rigged up and tested, the rig unseats the production packer, often by applying tension or rotating depending on packer type, then trips the tubing out one joint at a time, racking each stand and inspecting threads, body wall, and couplings. Damaged joints are laid down and replaced. If a subsurface safety valve, gas-lift mandrels, or a rod pump assembly are part of the completion, they come out with the string and are serviced or swapped before the new tubing is run, spaced out, and the packer reset.

Cost Drivers and Deferred Production

The economics of a tubing job hinge on three things: service rig day rate, the duration of the job, and the deferred production while the well is down. A single-well WCSB tubing job typically runs 3 to 7 days, with service rigs billing in the range of 1,500 to 4,000 CAD per hour all-in once ancillary services, kill fluid, and tubular handling are counted, putting a routine job at roughly 150,000 to 400,000 CAD. New tubing, a replacement packer, and a subsurface safety valve can add tens of thousands more. Against that, the operator weighs lost barrels during the shut-in and the upside of restored deliverability, which is why marginal wells are sometimes left shut in rather than worked over.

Related Terms

A tubing job is the signature operation of a workover, the broad category of major remedial work on an existing well. It requires a workover rig with the hook load and pipe-handling capacity to trip the full string. It is the heavier counterpart to coiled tubing and other through-tubing methods, which an operator prefers when the completion can stay in place. Because the well must be made safe first, every tubing job depends on a sound kill fluid and verified barriers to maintain well control while the tubing is out of the hole.

WCSB Scenario: Sour Gas Tubing Failure in a Foothills Well

A deep sour gas well in the Alberta Foothills, producing from a Nisku reservoir at about 3,400 metres, shows rising casing-annulus pressure on a routine integrity check, a clear sign the carbon-steel production tubing has been breached by sulfide attack. Under AER Directive 087 the operator cannot keep producing with a failed barrier, so a tubing job is mandatory. A service rig is mobilized, the well is killed with a weighted calcium bromide brine, and the corroded string is pulled and replaced with NACE-compliant 13 chrome tubing rated for the H2S partial pressure.

The job runs nine days and lands near 620,000 CAD once the corrosion-resistant tubing and a new packer are included, well above a routine workover because of the alloy and the sour-well controls. With integrity restored and a corrosion inhibition program added, the well returns to production and the annulus pressure stabilizes, protecting both the asset and regulatory standing.