casing test

A casing test is a pressure test applied to a casing string after it has been run and cemented in the wellbore, designed to verify that the casing body, connections, and cement sheath provide a pressure-tight barrier capable of containing the maximum anticipated wellbore pressures for the interval the casing isolates, and in Western Canada Sedimentary Basin well construction the casing test is a mandatory regulatory step performed at each casing string before drilling ahead or before perforating and completing the well. The casing test pressurizes the inside of the casing string by closing the blind rams or annular BOP at surface, applying pump pressure down the drill string or casing to the target test pressure, and then holding that pressure for a defined period (typically 15 to 30 minutes) while monitoring for pressure decline that would indicate a leak in the casing body, a connection, the float equipment, or the cement seal at the shoe. AER Directive 008 requires that casing strings be pressure tested to the lesser of 70 percent of the minimum internal yield pressure of the weakest joint in the string, the working pressure rating of the wellhead assembly, or a pressure that would fracture the formation at the casing shoe (limited to avoid damaging the formation being protected), with the test pressure documented in the well file and reported to the AER on the well completion report. The acceptable test result criterion in WCSB operations is that the applied pressure holds within 5 percent of the target test pressure for the full hold period with no visible surface leaks at the wellhead connections or BOP stack; a failed test (pressure decline exceeding 5 percent per 15 minutes, or any surface leakage) requires investigation and remediation before drilling continues, because a casing string that cannot hold the test pressure cannot reliably contain formation fluid influxes during drilling of the hole section below or wellbore pressure during production operations. Casing tests in WCSB operations occur at three distinct points in the well construction sequence: the surface casing test verifies integrity of the conductor-to-surface-casing annular seal and the surface casing body before drilling the intermediate hole section, typically testing to 10 to 25 MPa depending on the planned intermediate mud weight; the intermediate casing test verifies the surface-to-intermediate casing annulus seal and intermediate casing body before drilling the production hole section with the higher mud weights required to control the deeper formations, typically testing to 20 to 55 MPa; and the production casing test performed before perforating verifies that the production casing can contain the maximum anticipated hydraulic fracturing treating pressure (60 to 100 MPa for WCSB Montney and Duvernay horizontal wells) and reservoir shut-in pressure. Beyond the regulatory construction-phase tests, casing tests are also performed during workovers and intervention programs when production casing integrity is in question: a positive pressure test on the tubing-casing annulus confirms that the production casing is leak-free; a negative pressure test (swabbing the casing to below reservoir pressure to create an inward pressure differential) tests the casing's collapse resistance and the integrity of perforations to reservoir communication. Understanding casing test procedures, the regulatory test pressure and hold-time requirements under AER Directive 008, the interpretation of pressure decline versus acceptable bleed-down, and the remediation options when a casing test fails gives drilling engineers, completions engineers, wellsite supervisors, and well integrity specialists the technical framework to plan, execute, interpret, and respond to casing tests throughout the well construction and intervention lifecycle of WCSB wells.

• Test pressure calculation for WCSB casing strings: The casing test pressure is the minimum of three limiting values: 70% of the minimum internal yield pressure (MIYP) of the weakest joint in the string (calculated from API 5C3 Barlow formula for the lightest weight or lowest grade joint, typically the top joints exposed to the full test pressure); the wellhead assembly working pressure rating; and the maximum pressure that would not fracture the casing shoe formation (calculated from the shoe fracture gradient minus the fluid hydrostatic head at the shoe depth). For a WCSB Montney production casing string with a weakest joint MIYP of 74.4 MPa, a 5,000 psi (34.5 MPa) wellhead, and a shoe fracture gradient equivalent to 62 MPa at surface, the test pressure is limited to 34.5 MPa by the wellhead rating.
• Bleed-down acceptance criterion and leak investigation: A pressure decline of more than 5 percent of the applied test pressure during the 15 to 30-minute hold period indicates a potential leak in the system. The first step is to bleed down and re-pressurize to confirm the result is repeatable rather than a temperature artifact (thermal expansion of the test fluid can cause apparent pressure increase, while cooling can cause apparent decline in a sealed system). If confirmed, the leak source is isolated by sequential pressure testing of subsystems: the wellhead and surface connections are pressure-tested with blind flanges to isolate from the casing; if the surface system is sound, the casing body and connections are the source, requiring either a cement squeeze at a specific leak location identified by temperature log or a casing patch.
• Production casing pre-frac test requirements in WCSB multi-stage completions: Before hydraulic fracturing any WCSB Montney or Duvernay horizontal well, the production casing is pressure-tested to 110 percent of the planned maximum treating pressure to confirm the casing can withstand the stimulation without failure. AER Directive 083 requires this pre-stimulation casing test with the test pressure documented in the completion report. For Montney wells with planned treating pressures of 75 MPa, the casing test is conducted to 82.5 MPa; if the casing fails at less than this pressure, fracturing must be limited to the verified maximum hold pressure or the casing must be replaced before stimulation.
• Negative pressure test for inward barrier verification: A negative pressure test (NPT), also called an inflow test, pressurizes the well from the reservoir side rather than the surface side, verifying that the casing can hold a pressure differential from outside to inside. In WCSB workover operations, the NPT is performed by swabbing the casing fluid level down to create a partial vacuum above the fluid column, then monitoring for fluid inflow that would indicate a perforation or casing leak allowing reservoir fluid to enter the string from below the packer. Negative pressure tests are required by AER Directive 008 when returning a WCSB well to service after a workover that included casing patching, re-perforating, or packer replacement.
• Cement squeeze remediation after failed casing test: When a casing test fails at a specific depth identified by a temperature log or noise log (elevated temperature or acoustic signal at the leak point), a cement squeeze is designed to inject cement through a perforated or corroded casing section into the annular space behind the casing to seal the communication pathway. The squeeze pressure must exceed the formation parting pressure at the target depth to confirm that cement enters the annulus rather than the formation; a successful squeeze is verified by a repeat casing test that holds the target pressure without further decline. Failed squeezes require a casing patch or section mill as the remediation escalation.

Failed Production Casing Test Leading to Pre-Frac Casing Replacement on a WCSB Montney Well

A northeast British Columbia operator preparing a Montney horizontal well for hydraulic fracturing conducted the mandatory pre-stimulation casing test at 85 MPa (110% of the planned 77 MPa maximum treating pressure). Pressure climbed to 72 MPa and then declined at 1.8 MPa per minute, failing the 5% bleed-down criterion. A temperature log run inside the production casing identified an anomalous warm zone at 2,840 m (the build section) corresponding to a 4.7 MPa pressure differential from the vertical section above, indicating a connection leak at that depth. Two cement squeeze attempts through perforations opened adjacent to the joint at 2,840 m failed to seal the connection because the leak path was at the thread root of the connection rather than in the annular cement. The operator replaced 6 joints of production casing through the build section using a liner patch assembly set on a liner hanger at 2,750 m and cemented to 2,920 m. The repeat pre-frac casing test reached 85 MPa and held for 20 minutes with 0.8 MPa bleed-down (less than 1%). All 22 fracturing stages were completed without casing integrity events. Liner patch installation cost: $380,000; delay to fracturing program: 11 days. The connection leak was attributed to insufficient makeup torque applied during the original casing running operation, a finding that prompted the operator to add real-time torque monitoring to all subsequent casing running programs in the play.

Related Terms

Minimum internal yield pressure is the API 5C3 burst rating of the casing string that sets the upper limit of the casing test pressure at 70 percent of the weakest joint MIYP, ensuring the test pressure verifies leak integrity without plastically deforming or damaging the casing wall during the test. Formation integrity test is related but distinct from the casing test: while the casing test verifies the pressure integrity of the casing string itself, the formation integrity test pressurizes the open-hole formation below the casing shoe to measure the fracture gradient of the formation at that depth before drilling the next hole section. Cement squeeze is the primary remediation for a failed casing test where the leak path is through the annular cement behind the casing rather than through the casing body or connections, injecting fresh cement under pressure to fill the communication channel and restore the pressure-tight barrier that the test confirmed was absent. Casing inspection log (temperature log, noise log, multi-finger caliper, or electromagnetic inspection tool) is used after a failed casing test to identify the depth and nature of the leak before selecting the remediation approach, distinguishing between connection leaks, casing body perforations or corrosion, and annular cement deficiencies that require different repair strategies. Well integrity in WCSB operations depends on passing casing tests at each construction stage to confirm that the pressure barriers required by AER Directive 008 are in place before the next hole section is drilled or the well is put on production; a casing test failure that is remediated before drilling continues prevents the much more costly and hazardous scenario of a casing failure during high-pressure operations in the sections below.