closed-in well

A closed-in well is a producing, injection, or appraisal well in which all surface flow valves have been shut and the wellbore is sealed at the wellhead, preventing fluid or gas from flowing to the surface processing system, so that wellbore pressure can build toward the static formation pressure undisturbed by the drawdown effects of production; in Western Canada Sedimentary Basin field operations, wells are deliberately closed in for five principal purposes: controlled pressure buildup testing for reservoir characterization (measuring transmissibility, skin factor, and average drainage area pressure in WCSB Cardium, Viking, Montney, and Duvernay horizontal producers by recording the pressure recovery curve after a defined flowing period and analyzing it using Horner, Miller-Dyes-Hutchinson, or log-log pressure derivative methods); regulatory compliance with AER Directive 003 shut-in pressure reporting requirements (annual SIWHP tests are mandatory for all WCSB producing wells to confirm wellbore integrity and document reservoir pressure depletion trends for reservoir surveillance); sustained casing pressure investigation (monitoring annular pressure rebuild after bleeding to detect tubing leaks, packer failures, or cement gas migration in WCSB wells that show unexpected casing annulus pressure under shut-in conditions); well integrity confirmation before workover or abandonment operations (verifying surface casing integrity at full SIBHP before perforating, stimulation, or re-entry programs in nearby wellbores); and temporary production suspension from wells curtailed by gathering system constraints, low commodity prices, or regulatory hold orders pending compliance with WCSB environmental or wellbore integrity requirements. The fundamental measured parameter from a WCSB closed-in well is the shut-in wellhead pressure (SIWHP), which, when corrected for the hydrostatic gradient of the wellbore fluid column (gas, oil, or water from perforation midpoint to surface), gives the shut-in bottomhole pressure (SIBHP) representing average formation pressure in the near-wellbore drainage area after sufficient closed-in time for pressure equalization; comparing SIBHP trends over the producing life of a WCSB Cardium or Viking waterflood pool provides the material balance data used to calculate reservoir depletion, voidage replacement ratio, and aquifer influx in the absence of dedicated pressure observation wells.

• Pressure buildup testing and Horner analysis of WCSB Cardium and Viking closed-in well data: Pressure buildup (PBU) testing in WCSB producing wells involves shutting in a well that has been producing at a stabilized rate and recording the wellbore pressure recovery with a downhole memory gauge or permanent downhole gauge (PDG) at 1 to 10 second sampling intervals for 12 to 72 hours, followed by analysis of the shut-in pressure-time data on a Horner plot (log of (tp plus delta-t) divided by delta-t versus shut-in pressure) to extract permeability-thickness product (kh), skin factor, and extrapolated static BHP. In WCSB Cardium horizontal producers with formation permeability of 1 to 20 mD, pressure stabilization after shut-in requires 12 to 48 hours, during which the pressure derivative on the log-log diagnostic plot transitions through wellbore storage dominance (unit slope on both pressure and derivative), then radial flow (flat derivative plateau from which kh equals 70.6 times flowing rate times oil FVF times viscosity divided by slope of derivative plateau times net pay in oilfield units), then possible boundary effects (rising derivative indicating drainage area limits). Skin factor calculated from WCSB Cardium PBU data ranges from minus 3 to minus 6 in successfully stimulated acidized wells (indicating improved permeability near the wellbore) to plus 10 to plus 30 in wells with severe formation damage from clay fines plugging or scale deposition at the perforations, providing the quantitative justification for workover decisions to re-acidize or clean out perforations in underperforming WCSB producers.
• AER regulatory closed-in pressure test requirements for WCSB producing wells: AER Directive 003 (Directive for Suspension, Abandonment, Decontamination, and Reclamation of Wells, Facilities, and Associated Sites) and AER Directive 040 require WCSB operators to conduct and document periodic shut-in wellhead pressure tests on all active producing and suspended wells to confirm wellbore integrity and compliance with surface casing vent flow (SCVF) and gas migration (GM) reporting obligations. A WCSB SIWHP test under AER requirements consists of shutting in the well, waiting for pressure stabilization (minimum 2 hours for most well types, 24 hours for tight gas wells with SIBHP extrapolation uncertainty), recording the stabilized SIWHP on a certified pressure gauge, and comparing against the well's historical SIWHP trend; a SIWHP declining faster than the pool average depletion rate triggers investigation for wellbore integrity issues (casing leak communicating with a depleted zone), while a SIWHP that fails to build at all after shut-in indicates formation plugging (scale, paraffin, or asphaltene blocking the perforations or near-wellbore matrix). Surface casing vent flow (SCVF) is detected by monitoring the surface casing annulus for pressure buildup under closed-in conditions; any SCVF above 300 m3/d or 2,000 Pa/s requires immediate AER notification and corrective action under Directive 020 in WCSB Alberta operations.
• Shut-in bottomhole pressure measurement and wellbore fluid gradient in WCSB gas and oil wells: Calculating SIBHP from measured SIWHP requires accurate knowledge of the wellbore fluid gradient from perforations to wellhead, which differs between WCSB gas, oil, and water-producing wells. In WCSB Montney dry gas wells with SIWHP of 15,000 to 20,000 kPa and wellbore full of gas at 0.05 to 0.07 SG gradient, the hydrostatic correction for a 2,500 m well is only 1,200 to 1,750 kPa (gas column), making SIBHP approximately 16,200 to 21,750 kPa; in WCSB Cardium oil wells with SIWHP of 5,000 to 9,000 kPa and wellbore partially loaded with oil at 0.80 to 0.85 SG gradient, the hydrostatic correction for a 1,500 m well is 12,000 to 12,750 kPa, making SIBHP 17,000 to 21,750 kPa despite the much lower surface reading. Error in the fluid gradient assumption propagates directly into SIBHP error; for WCSB liquid-loaded gas wells where the wellbore contains a gas cap above a liquid column of unknown height, SIBHP uncertainty from gradient error can be 500 to 2,000 kPa, comparable to or exceeding the pressure depletion being tracked, requiring downhole gauge data to eliminate the ambiguity. Permanent downhole gauges (PDGs) installed in WCSB Montney and Duvernay horizontal wells at completion eliminate the gradient correction entirely by measuring BHP directly, enabling real-time material balance and continuous reservoir pressure monitoring without the production deferral cost of periodic closed-in tests.
• Sustained casing pressure detection and investigation in closed-in WCSB wells: Sustained casing pressure (SCP) is pressure that continuously rebuilds on a casing annulus after bleeding down to zero, indicating a subsurface source is continuously charging the annulus through a wellbore integrity leak. SCP investigation in WCSB wells is conducted under closed-in conditions because wellbore dynamics during production mask the annulus pressure signal; with the well shut in and the wellbore static, any pressure buildup on the surface casing annulus after bleeding to atmospheric must originate from a subsurface path: a tubing pin-box connection leak (most common in WCSB wells with cyclic thermal loading from intermittent production), a packer element failure allowing interzonal communication, or a gas migration path through microannulus in the primary cement behind the production or intermediate casing. AER Directive 020 classifies SCP rebuild rates in WCSB wells: Category I (above 2,000 Pa/s or 300 m3/d equivalent gas flow rate) requires immediate shutdown and remediation; Category II (50 to 2,000 Pa/s) requires investigation plan within 30 days; Category III (below 50 Pa/s with stable maximum pressure) is monitored. SCP remediation in WCSB wells typically uses a squeeze cement job to seal the cement microannulus or a straddle tool to isolate a leaking tubing connection.
• Material balance from closed-in pressure surveys in WCSB waterflood pools: Systematic SIWHP surveys across multiple closed-in wells in a WCSB Cardium or Viking waterflood pool constitute a material balance dataset when the survey is conducted simultaneously (all wells shut in on the same day) and the SIBHP is extrapolated from short buildup data using Horner analysis to remove the skin-affected near-wellbore component. The average SIBHP across a WCSB waterflood pool, weighted by kh of each well, represents the average reservoir pressure in the pool at the survey date; tracking average pool pressure versus cumulative production and injection over time provides the material balance equation inputs: cumulative oil withdrawal, gas cap expansion (if present), connate water expansion, and water influx from injection or aquifer. In WCSB Cardium waterflood pools with voidage replacement ratios (VRR) below 0.8 (injection less than withdrawal), average pool SIBHP declines at a rate predictable from material balance; VRR above 1.2 causes pool pressure maintenance or increase that can be confirmed by improving SIBHP trends across all closed-in producer surveys and is used to optimize injection rates before the pool becomes overpressured relative to surface casing integrity limits.

Pressure Buildup Analysis Identifying Formation Damage in WCSB Cardium Producer

A WCSB Cardium oil well in the Pembina area had declined from 18 m3/d at completion to 6 m3/d over 14 months despite the pool average declining only 15 percent. A 48-hour pressure buildup test was conducted: the well was shut in after 24 hours of stabilized production at 6 m3/d, with a downhole memory gauge recording at 5-second intervals. Horner analysis of the radial flow period (identified as the flat derivative plateau from hours 8 to 32 of shut-in) gave kh of 310 mD-m, consistent with offset core data, and skin factor of plus 28, indicating severe near-wellbore damage. SIBHP extrapolated to 19,800 kPa versus original pool pressure of 22,400 kPa (12 percent depletion, expected for the pool). Scale analysis identified CaCO3 in the perforation core debris. An HCl acid job pumped into the perforations reduced skin from plus 28 to minus 2 (confirmed by post-treatment PBU), restoring production to 16 m3/d within 30 days. The closed-in PBU data differentiated formation damage (high skin) from reservoir depletion (normal SIBHP) and directed the workover rather than a premature recompletion in a new zone.

Related Terms

Pressure buildup test is the primary reservoir characterization purpose for closing in WCSB Cardium, Viking, and Montney producers; Horner analysis of the recovery curve yields transmissibility, skin, and static BHP from which workover and stimulation decisions are made. Shut-in wellhead pressure is the primary measurement from a closed-in WCSB well; corrected for wellbore fluid gradient, it gives shut-in bottomhole pressure for material balance and depletion tracking. Sustained casing pressure is detected on casing annuli under closed-in conditions; AER Directive 020 classifies WCSB SCP by rebuild rate and requires investigation plans for Category I and II events. Skin factor quantifies near-wellbore damage or stimulation; Horner PBU analysis of a closed-in WCSB producer identifies high positive skin (damage requiring acid workover) from normal reservoir depletion. Material balance calculations for WCSB waterflood pool management use SIBHP surveys from simultaneously closed-in producers to track average pool pressure versus voidage replacement ratio.