close-in

Close-in pressure in oil and gas well operations refers to the stabilized wellhead or bottomhole pressure measured after a producing well has been shut in for a defined period sufficient to allow near-wellbore pressure transients to dissipate and the pressure to approach static reservoir conditions, providing a practical measurement of formation pressure that guides production engineering decisions including artificial lift design, reservoir depletion monitoring, and production allocation; the term is used across several distinct but related contexts in Western Canada Sedimentary Basin operations, most commonly as the shut-in wellhead pressure (SIWHP) recorded on daily production reports and gas well deliverability tests, as the instantaneous shut-in pressure (ISIP) measured immediately after hydraulic fracturing operations cease pumping to determine the minimum principal stress from the pressure falloff curve, and as the close-in tubing pressure used in WCSB gas well absolute open flow (AOF) tests conducted under AER Directive 040 modified isochronal test procedures. In WCSB gas well production surveillance, the close-in pressure recorded after a minimum 72-hour shut-in period on wells with permeability below 0.1 mD (tight Cardium, Notikewin, Cadomin, and Spirit River sands) represents a practical approximation of average reservoir pressure within the drainage area, because low-permeability formations require extended shut-in times for wellbore storage effects to clear and for the pressure transient to propagate far enough into the formation that the measured pressure reflects true static reservoir conditions rather than the locally depleted near-wellbore region; a 72-hour shut-in is the AER minimum for deliverability testing of tight gas wells, but in WCSB ultralight formation with permeability below 0.01 mD (Montney, Duvernay), true reservoir pressure is not achieved without shut-ins of 7 to 21 days, requiring operators to apply superposition analysis in pressure buildup interpretation (Horner method, extended Blasingame) to extrapolate the measured pressure trend to true static pressure. In WCSB hydraulic fracturing operations, the ISIP measured at the end of each fracturing stage provides the only direct measurement of minimum horizontal stress available during the completion program; ISIP values from each perforation cluster stage are plotted against true vertical depth to construct the stress profile along the lateral, identifying intervals where the stress is elevated (natural barriers to fracture height growth) or reduced (preferred fracture initiation zones) and calibrating the geomechanical model used for subsequent stage design.

• Close-in pressure measurement procedures for WCSB gas well deliverability testing under AER Directive 040: AER Directive 040 (Measurement Requirements for Oil and Gas Operations) specifies close-in pressure measurement protocols for WCSB gas well deliverability tests. In a modified isochronal test, the well is produced at four stabilized rates for equal periods (typically 4 to 8 hours each), with a close-in period between each flow period sufficient to allow the wellbore pressure to recover to within 5 percent of the original static pressure (the pre-test close-in pressure); for tight WCSB Spirit River and Cadomin gas sands with permeability of 0.01 to 0.1 mD, the between-rate close-in periods must be 6 to 24 hours to achieve adequate pressure recovery. The pre-test close-in pressure (static wellhead pressure after minimum 72 hours shut-in) is the reference against which all flowing bottomhole pressures are compared to calculate the deliverability curve (log-log plot of flow rate versus pressure-squared drawdown); an incorrect close-in pressure reference caused by insufficient shut-in time leads to underestimation of the true driving pressure and consequently overestimation of formation permeability and AOF on the deliverability curve.
• Instantaneous shut-in pressure (ISIP) from hydraulic fracturing and minimum stress determination in WCSB completions: In WCSB multi-stage hydraulic fracturing of Montney, Duvernay, and Cardium horizontal wells, the ISIP recorded within 30 to 90 seconds after pump shutdown at the end of each stage is the primary real-time indicator of the fracture closure pressure, which equals the minimum horizontal stress when the fracture is hydraulically propped open by fluid pressure but before proppant bridging occurs. A typical WCSB Montney horizontal lateral shows ISIP values of 35 to 55 MPa decreasing systematically from heel to toe as the lateral moves into lower-stress rock; ISIP values that are anomalously high relative to adjacent stages indicate natural fracture networks or inter-stage communication where hydraulic fracture fluid has leaked into a pre-existing fracture system that maintained a higher local stress. The difference between the breakdown pressure (peak treating pressure) and the ISIP is the net pressure at the moment of fracture initiation, which geomechanical engineers use to calibrate fracture propagation models; WCSB Duvernay completions with breakdown pressures of 80 to 100 MPa and ISIP values of 50 to 60 MPa show net pressures of 25 to 40 MPa, consistent with complex fracture network development in the highly stressed brittle Duvernay matrix.
• Close-in pressure decline monitoring for WCSB reservoir pressure depletion tracking and drainage confirmation: Sequential close-in pressure measurements taken at 6-month or annual intervals from WCSB producing wells provide a practical reservoir pressure depletion history that does not require dedicated pressure transient tests; the rate of close-in pressure decline reflects the rate of reservoir energy depletion within the drainage area and can be used to estimate reservoir volume connected to the wellbore. In a WCSB Cardium oil pool with initial reservoir pressure of 14 MPa and a close-in pressure decline of 0.8 MPa/year at a production rate of 8 m3/d of oil plus solution gas, material balance analysis using the measured close-in pressure trend and cumulative production confirms a connected pore volume of approximately 85,000 m3 (equivalent to 20 hectares of 4 m net pay at 15 percent porosity). WCSB operators use declining close-in pressure trends to justify infill drilling when the close-in pressure at a given well has declined more than 30 percent from initial (indicating advanced local depletion) while offset wells on a 640-acre spacing show less depletion, suggesting a drainage barrier between the two wells that infill wells could bridge.
• Close-in casing pressure monitoring for WCSB sustained casing pressure detection and well integrity assessment: Close-in casing pressure (the pressure measured on the casing annulus with the well shut in at the wellhead) is a distinct diagnostic measurement from close-in tubing pressure used in deliverability testing; close-in casing pressure in a WCSB oil or gas well that is non-zero after bleeding to atmosphere and allowing 24 hours shut-in indicates sustained casing pressure (SCP) caused by gas migration through the cement sheath or casing integrity failure. AER Directive 020 requires WCSB operators to report SCP above defined thresholds (surface casing: any positive casing pressure sustained more than 24 hours after bleed-down; production casing: pressure above 500 kPa sustained 24 hours after bleed-down) and to evaluate the source and risk of the casing pressure using a diagnostic bleed-down and build-up test. Close-in casing pressure build-up rate after bleed-down (kPa/hour) is the primary indicator of SCP severity; a build-up rate above 50 kPa/hour on a WCSB production casing annulus indicates active gas migration requiring remediation planning, while a build-up rate below 5 kPa/hour may indicate trapped expansion pressure from temperature cycling that dissipates naturally without indicating a cement integrity problem.
• Strategic shut-in (close-in) decisions in WCSB heavy oil and gas operations during low-price environments: Close-in as a production strategy refers to the deliberate shut-in of WCSB producing wells during periods of low oil or gas price to avoid producing at below-operating-cost netbacks, preserving reservoir energy for production restart when prices recover. WCSB heavy oil producers shut in wells with operating costs above $20/bbl when WCS differentials widen to $25 to $35/bbl below WTI (as occurred in late 2018 and early 2020), temporarily stopping reservoir depletion and allowing bottomhole pressure to recover; in unconsolidated Mannville sand CHOPS wells, a close-in period of 30 to 90 days allows near-wellbore pressure to partially recover, often resulting in a production spike (above pre-shut-in rate) of 10 to 30 percent for the first 30 to 60 days after restart as the re-pressurized reservoir drives oil through the wormhole network at elevated rates. AER requires operators to notify the regulator of planned shut-ins exceeding 90 days under Directive 056 event reporting provisions, and to submit a production resumption plan confirming wellbore integrity before restart.

ISIP Stress Profile Identifying Natural Fracture Barrier in WCSB Montney Lateral Completion

A northeast British Columbia Montney horizontal lateral with 28 perforation cluster stages showed ISIP values of 42 to 49 MPa for stages 1 through 18 (toe to mid-lateral) but an anomalous increase to 58 to 63 MPa for stages 19 through 24, followed by a return to 44 to 50 MPa for stages 25 to 28 near the heel. Post-job microseismic mapping confirmed that stages 19 to 24 fell within a 300 m zone of elevated natural fracture density mapped from image log data, where the pre-existing fracture system had been reactivated during earlier stages and elevated local pore pressure, increasing the effective minimum stress measured as ISIP. The completion engineer redesigned the proppant schedule for the elevated-ISIP zone (reducing proppant concentration by 30 percent to prevent screen-out in the tighter natural fracture network) and flagged these stages for future refrac targeting because the elevated ISIP indicated complex fracture geometry with likely higher residual aperture. The 12-month cumulative production from the lateral was 195 MMcf; stages 19 to 24 contributed 22 percent of total production despite covering only 21 percent of lateral length, confirming the elevated natural fracture density in that zone as a productivity sweet spot.

Related Terms

Shut-in pressure is the equivalent term for close-in pressure in most WCSB regulatory and engineering documents; the shut-in wellhead pressure (SIWHP) recorded on daily production reports and AER monthly production submissions is the close-in pressure measurement used for reservoir depletion monitoring across WCSB oil and gas pools. Instantaneous shut-in pressure (ISIP) is the specific close-in pressure measurement taken within seconds of stopping hydraulic fracturing pumps; ISIP values across all stages of a WCSB Montney or Duvernay horizontal completion build the minimum horizontal stress profile used to calibrate geomechanical models and refrac candidate selection. Deliverability test under AER Directive 040 uses close-in pressure as the static reference for WCSB gas well AOF calculation; the pre-test 72-hour close-in pressure is compared to flowing bottomhole pressures at four rates to construct the backpressure curve. Sustained casing pressure (SCP) is detected through close-in casing pressure monitoring at WCSB wellheads; non-zero casing pressure sustained after bleed-down triggers AER Directive 020 reporting obligations and well integrity investigation programs. Pressure buildup test is the formal pressure transient analysis method that uses the same shut-in data as close-in pressure measurement but analyzes the full buildup curve with Horner or superposition methods to determine permeability, skin, and extrapolated static pressure in WCSB reservoir characterization programs.