tubing testing tool, Oil & Gas Glossary

A tubing testing tool is a downhole mechanical device used to plug the bottom of a production tubing string, isolating the tubing internal volume from the formation below, so that the assembled tubing string can be hydrostatically pressure tested to verify its mechanical integrity and the seal of every threaded connection. The tool is most commonly deployed on slickline, a single-strand non-electric wireline of 0.108 inch (2.74 mm) high-tensile steel that uses a stem and impact-jar to set and retrieve the device. The plug seats inside the tubing at a profiled landing nipple, in a no-go shoulder, or by an expanding bow-spring anchor with a sealing element typically rated to 10,000 psi (69,000 kPa) differential pressure or higher. After the plug is set and verified by an upward pull test, the tubing is pressured up from surface in stages, commonly to 70% of pipe burst rating or to a value specified by the operator's well construction standard, often 5,000 to 10,000 psi (34,500 to 69,000 kPa) for typical WCSB production tubing such as 73 mm (2-7/8 in) L80 or P110. The pressure is held for a defined period, commonly 30 minutes, and the chart-recorded decline is compared against the allowable leak rate, typically 5% or less of the test pressure over 10 minutes. Any greater decline triggers a leak hunt: connections are inspected, the plug seal is verified, surface valves are isolated, and a re-test is performed. Tubing testing tools are most useful in vertical or slightly deviated wellbores up to roughly 60 degrees inclination, beyond which slickline gravity-driven deployment becomes unreliable and operators switch to electric line or coiled tubing for tool conveyance. The test is required at multiple points in a well's life: initial completion (verifying connections from the wellhead to the production packer), workover (after a tubing change-out or repair), recompletion to a new zone, and prior to perforating in some operator-specific programs. Under AER Directive 008 (Surface Casing Depth Requirements) and Directive 020 (Well Abandonment), tubing integrity testing is part of the documented mechanical integrity record that operators must maintain. The tool itself is small, typically less than 1.5 m long and weighing 15 to 50 kg, but it sits at a critical point in the well's barrier philosophy. A tubing string with an unverified leak can allow produced gas to migrate up the annulus to surface, breach the production casing, or contaminate a freshwater aquifer, all of which trigger AER incident reporting under Directive 019. The combination of slickline-deployed test plug, surface pressure pump truck, and digital chart recorder is the standard WCSB tubing integrity test rig-up, costing approximately CAD 8,000 to 15,000 per well per test event including service crew time and consumables.

Key Takeaways

Bottom-of-tubing isolation device: The tubing testing tool seats inside the production tubing at a profile or landing nipple, plugging the ID so the tubing can be pressured from surface without communicating with the formation. Common slickline-deployed designs include the type X profile lock plug and the BPV (back pressure valve), both rated for differential pressures of 10,000 to 15,000 psi (69,000 to 103,000 kPa) in standard WCSB applications.
Slickline is the primary conveyance method: Most tubing testing tools are run on 0.108 inch (2.74 mm) slickline using a sinker bar, jar, and pulling tool assembly. Slickline is well-suited for vertical and lightly deviated wells up to about 60 degree inclination. In highly deviated or horizontal wellbores, electric line or coiled tubing is used instead because gravity is no longer sufficient to drive the tool downhole.
Test pressure typically 70% of pipe burst rating: Standard WCSB tubing test pressures are 5,000 to 10,000 psi (34,500 to 69,000 kPa) for typical 73 mm L80 or P110 production tubing. Pressure is held for 30 minutes with a chart-recorded decline of less than 5% over 10 minutes generally accepted as a pass. Higher-rated sour service (NACE MR0175 compliant) wells may test at lower pressures with stricter leak rate tolerances.
Required at multiple lifecycle events: Initial completion, every workover that touches the tubing, recompletion to a new zone, and (under some operator programs) prior to perforating. The chart record is retained as part of the well's mechanical integrity file under AER recordkeeping requirements and is part of the documented barrier verification submitted with abandonment applications under Directive 020.
Detects leaks before they become surface incidents: An unverified tubing leak can allow produced gas to bypass into the annulus, pressure the casing, breach surface casing, or contaminate fresh groundwater zones. Each of these triggers reportable releases under AER Directive 019. A CAD 10,000 tubing integrity test is the cheapest insurance against a six- or seven-figure remediation event, which is why operator policy typically requires the test at every tubing-touching workover.

Slickline Deployment and Plug Setting

A typical slickline rig-up consists of a slickline truck or skid with a hydraulic winch, a lubricator stack, a stuffing box pressure seal, and a 50 to 75 m mast. The tool string is assembled at surface: a 60 to 90 kg sinker bar at top, a hydraulic or mechanical jar in the middle, the test plug at the bottom, and a Type X or B running tool attaching the plug to the string. The string is run in hole at controlled speed (typically 60 to 120 m/min), lowered through the tubing until the plug seats at the target profile nipple, and downward jarring strokes set the lock dogs into the profile groove. An upward pull test confirms the plug is locked. The running tool releases and is pulled back to surface, leaving the plug seated. Total deployment for a typical vertical 2,500 m well runs about 4 to 6 hours including rig-up and rig-down.

Pressure Test and Decline Interpretation

With the plug seated and verified, a pressure pump truck is rigged to the tubing wing valve. Pressure is built up in steps of 1,000 to 2,000 kPa (145 to 290 psi) to the target test pressure, holding briefly at each step to observe stability. Once at full test pressure (commonly 35,000 to 70,000 kPa or 5,000 to 10,000 psi), the pump is isolated and a digital chart recorder logs surface pressure for 30 minutes. The decline curve is interpreted: a smooth slight decline is typically thermal equilibration as the test fluid cools, while a steepening or sustained decline indicates a real leak. Typical acceptable decline is less than 5% of test pressure over 10 minutes. Failed tests trigger a leak hunt and a re-test after correction.

Fast Facts

Slickline was invented in 1929 by Otis Pressure Control in Dallas as a way to operate downhole shut-in valves on oil wells without the cost of running tubing. The first downhole test plug designs followed in the early 1940s, driven by the need to verify tubing integrity in deeper East Texas wells where tubing leaks were causing significant lost production. The modern Type X profile lock, still in widespread WCSB use today, was patented by Otis in 1959 and remains essentially unchanged in design, a remarkable longevity for any oilfield mechanical device.

Tubing testing tools sit within the broader vocabulary of completion integrity and well intervention. Slickline is the primary conveyance method that delivers the tool downhole, while landing nipple is the profiled receptacle the tool seats inside. Bridge plug is a related but heavier-duty isolation device used for casing or larger-bore applications, and packer is the permanent isolation barrier between tubing and casing that the tubing testing tool is often used to pressure-test against. Together these terms describe the mechanical barrier philosophy that defines modern WCSB well construction.

WCSB Field Scenario: Cardium Workover Integrity Test at Pembina

A Cenovus Pembina Cardium horizontal well undergoes a tubing change-out after the existing 73 mm L80 string is found to have produced-water induced internal corrosion above the production packer. The new tubing is run, the packer is reset at 1,820 m, and the wellhead is dressed. A slickline crew rigs in at the wellsite for the integrity test, costing CAD 9,200 for the day including truck mobilization, two operators, and lubricator rental. A Type X profile plug is run to 1,810 m, immediately above the new packer, and set into the existing profile nipple.

The pressure pump truck builds tubing pressure to 48,000 kPa (7,000 psi), 70% of the L80 burst rating. The 30-minute hold shows a decline of 1,150 kPa (167 psi), a 2.4% drop, well within the 5% allowable. The chart is signed by the wellsite supervisor and added to the well's mechanical integrity file under AER recordkeeping. The plug is retrieved, the well is opened to production, and the entire test event takes 7 hours, avoiding the much larger cost of finding the leak after the well was returned to production.