casing pressure

Casing pressure is the pressure measured at the wellhead on the annular space between the production tubing and the innermost casing string (the tubing-casing annulus, or A-annulus), or more broadly any pressure measured on any casing annulus at the wellhead during drilling, completion, or production operations, serving as a primary well control parameter during drilling kicks and a well integrity monitoring parameter throughout the producing life of the well in Western Canada Sedimentary Basin oil and gas operations. During well control operations, the casing pressure (also called annular pressure or casinghead pressure in a drilling context) is the surface manifestation of the bottomhole pressure transmitted through the annulus above the influx, and the driller and well control personnel read the stabilized shut-in casing pressure (SICP) after closing the blowout preventer to calculate the kick intensity (the underbalance pressure that allowed formation fluid to enter the wellbore) and to design the kill mud weight required to restore primary well control. The SICP is the pressure at surface in the annulus with the BOP closed and fluid movement stopped; it represents the formation pressure at the kick depth minus the hydrostatic head of the annular fluid column above the kick, and for a gas kick it increases over time as the gas migrates upward and the gas column (which is lighter than mud) replaces mud in the annular column, a phenomenon called gas migration that requires active pressure management through controlled gas bleeding or volumetric well control procedures. In WCSB production operations, casing pressure on the tubing-casing annulus is monitored for sustained casing pressure (SCP), which is defined as pressure in a casing annulus that rebuilds after being bled down and indicates a leak in either the production tubing, the wellhead packing, or the production packer that is allowing reservoir pressure to communicate with the annular space; AER Directive 020 requires Alberta operators to document, investigate, and report all sustained casing pressures above defined thresholds, classifying SCP by the annulus it appears in (A-annulus between tubing and production casing, B-annulus between production casing and intermediate casing, C-annulus between intermediate and surface casing) and by whether the source is identifiable. The distinction between tubing-casing annulus pressure used for artificial lift gas injection (gas lift wells inject gas down the A-annulus to lighten the tubing fluid column, and the annulus operating pressure is a controlled production parameter rather than an integrity concern) and unintended SCP from tubing or packer leaks is operationally important in WCSB gas lift operations, where the wellhead casing pressure gauge routinely reads the gas injection pressure of 3 to 12 MPa and must be distinguished from anomalous pressure buildup indicating a tubing integrity failure. Casing pressure management during WCSB hydraulic fracturing operations involves monitoring the B-annulus (between production casing and intermediate casing or surface casing) for pressure buildup that would indicate a casing integrity failure during stimulation, with real-time annular pressure monitoring required under AER Directive 083 for all multi-stage hydraulic fracturing operations; B-annulus pressure exceeding the pre-stimulation baseline by more than 700 kPa during fracturing is a mandatory stop-work trigger requiring wellbore investigation before fracturing resumes. Understanding casing pressure measurement, the distinction between SICP during well control and SCP during production, the gas migration mechanism during kick control, the AER Directive 020 classification and reporting requirements for sustained casing pressure, and the B-annulus monitoring requirements during WCSB fracturing operations gives drilling engineers, production engineers, wellsite supervisors, and well control specialists the technical framework to respond correctly to elevated casing pressures in all operational contexts throughout the well lifecycle.

• Shut-in casing pressure and kick intensity calculation: After closing the BOP on a WCSB well kick, the stabilized SICP is read from the annulus pressure gauge and used with the shut-in drill pipe pressure (SIDPP) to calculate kick intensity: kick intensity (in equivalent mud weight) equals SIDPP divided by 0.00981 times depth (in metres). For a WCSB Montney horizontal well with SIDPP of 4.5 MPa and kick detected at 4,000 m TVD, kick intensity equals 4.5/(0.00981 x 4,000) = 0.115 sg above the current mud weight, requiring a kill mud weight increase of 0.115 sg (115 kg/m3). The SICP at stabilization is typically lower than the SIDPP because of annular friction and mud weight differences, but for gas kicks the SICP may exceed SIDPP if gas migration has reduced the annular hydrostatic head.
• Sustained casing pressure classification under AER Directive 020: AER Directive 020 classifies sustained casing pressure by annulus location and bleed-down behavior: A-annulus SCP (between tubing and production casing) that rebuilds above 690 kPa after bleeding to zero requires investigation within 30 days; B-annulus SCP (between production casing and surface/intermediate casing) that rebuilds above 690 kPa is a higher-severity finding requiring investigation within 14 days; SCP in any annulus above 50% of the annulus pressure test rating is an immediate reportable event. Operators must maintain annular pressure monitoring records and submit annual SCP status reports to the AER for all wells with documented sustained pressures.
• Gas migration during well control and volumetric method: When a gas kick is shut in on a WCSB well, the gas migrates upward through the annular mud column at rates of 30 to 120 m/hour (depending on mud viscosity, gas bubble size, and wellbore inclination), causing casing pressure to increase at surface even with the BOP closed. The volumetric well control method manages this pressure increase by bleeding small controlled volumes of mud from the choke while maintaining a constant safety pressure margin above formation pressure, preventing casing pressure from exceeding the maximum allowable annular surface pressure (MAASP, the pressure above which the previous casing shoe would fracture and be lost to the formation).
• B-annulus monitoring during WCSB fracturing operations: AER Directive 083 requires continuous B-annulus pressure monitoring during all hydraulic fracturing operations in Alberta, with the annulus gauge recorded at minimum 1-minute intervals throughout each fracturing stage. A B-annulus pressure increase of more than 700 kPa above the pre-frac baseline is a mandatory pump stop trigger; the most common cause is a casing connection leak or a casing body failure at a location where the stimulation pressure exceeds the pipe rating. All B-annulus pressure events during WCSB multi-stage fracturing must be documented in the completion report submitted to the AER after well completion.
• Casing pressure in gas lift operations: WCSB gas lift wells inject lift gas down the tubing-casing annulus at operating pressures of 3 to 12 MPa, with the wellhead casing pressure gauge reading the gas injection pressure as a normal operating parameter. Distinguishing gas lift injection pressure from anomalous SCP requires comparing the casing pressure against the gas lift design injection pressure: if casing pressure remains stable at the injection operating pressure and does not rebuild after controlled bleed-down beyond what is explained by gas injection rate, the annulus is performing as designed. Anomalous rebuilding (pressure returning faster than injected gas supply) or pressure appearance in the B-annulus indicates a leak in the gas lift mandrels, valves, or packer that requires workover investigation.

Sustained Casing Pressure Investigation on a WCSB Viking Producer

A Viking Formation producer in east-central Alberta showed A-annulus pressure of 1,850 kPa rebuilding to 2,100 kPa within 4 hours after bleed-down, triggering an AER Directive 020 investigation requirement. The operator performed a tubing pressure test (set surface tree and applied 10 MPa to tubing with annulus monitored for pressure response): annulus pressure increased at 380 kPa/hour during the tubing test, confirming a tubing leak transmitting tubing pressure to the A-annulus. Wireline depth correlation with a tubing inspection log identified a pinhole corrosion perforation at 890 m in a joint of 60.3 mm tubing where the inhibitor program had been interrupted 18 months earlier. The workover involved pulling and replacing the tubing string from 890 m to the packer, installing new NACE-compliant tubing in the corrosive interval, and resuming the corrosion inhibitor program with a downhole chemical injection valve. Post-workover A-annulus pressure was zero and remained zero at the 30-day follow-up inspection. Total workover cost was $145,000; SCP report to the AER was closed with the remediation documentation submitted within the required 30-day window.

Related Terms

Shut-in casing pressure is the stabilized annular pressure read at the wellhead after closing the blowout preventer on a kick influx, used with shut-in drill pipe pressure to calculate kick intensity and kill mud weight in the WCSB well control driller's method and engineer's method procedures. Sustained casing pressure is the production-phase well integrity concern where casing annulus pressure rebuilds after bleed-down, indicating a leak path from a higher-pressure source into the annulus; AER Directive 020 establishes the classification, investigation timeline, and reporting requirements for all WCSB sustained casing pressure events. Gas migration is the upward movement of a gas kick through the annular mud column after shut-in, causing progressive casing pressure increase that must be managed by the volumetric well control method or controlled gas bleeding to prevent SICP from exceeding the maximum allowable annular surface pressure at the previous casing shoe. Blowout preventer is the wellhead pressure control equipment whose closure isolates the annulus and allows the stabilized shut-in casing pressure to be read; the BOP stack configuration (annular BOP, pipe rams, blind/shear rams) and the rated working pressure of the BOP must be equal to or greater than the maximum anticipated SICP for the deepest formation to be drilled in the WCSB well program. Well control procedures for WCSB kick situations use the shut-in casing pressure as a primary diagnostic measurement to classify the kick type (gas, oil, or water), estimate kick volume from the gain in pit volume relative to pressure buildup, and design the kill procedure to safely circulate the influx out of the wellbore while restoring primary pressure control.