closure pressure

Closure pressure in hydraulic fracture engineering is the fluid pressure at which a hydraulic fracture mechanically closes after injection stops, numerically equal to the minimum principal in-situ stress acting perpendicular to the fracture plane, which in the normal faulting extensional tectonic setting dominant across the Western Canada Sedimentary Basin equals the minimum horizontal stress (sigma-h-min); closure pressure is the single most critical parameter in hydraulic fracture completion design because it defines the floor pressure that the fracturing treatment must sustain in the fracture during pumping to keep the fracture width open for proppant transport, and it establishes the net pressure (treating pressure minus closure pressure) that drives fracture aperture and determines whether the fracture grows in height into bounding barriers or propagates laterally within the target formation. In WCSB completion engineering for Montney, Duvernay, Cardium, and Viking formations, closure pressure is measured from diagnostic fracture injection tests (DFITs, also called minifrac tests or step-rate injection tests) in which a small volume of fluid (20 to 500 m3 in typical WCSB tight gas applications) is injected at a rate exceeding the fracture extension rate to create a small hydraulic fracture, then the well is shut in and the wellbore pressure decline is monitored for 12 to 96 hours as fracture fluid leaks off into the formation matrix; closure pressure is identified from the pressure fall-off record as the point at which the fracture faces contact and fluid leak-off transitions from fracture-face dominated to matrix dominated, appearing as a characteristic inflection on the G-function plot (pressure versus dimensionless time function developed by Nolte, 1979) or as a change in slope on the square root of shut-in time plot. Closure pressure in WCSB Montney horizontal wells typically ranges from 35 to 55 MPa at 2,000 to 3,500 m depth (gradients of 14 to 18 kPa/m), reflecting the compressional stress regime near the Rocky Mountain front where minimum horizontal stress is 70 to 85 percent of overburden; in the WCSB Cardium Formation at 1,200 to 2,000 m depth, closure pressure ranges from 15 to 30 MPa (gradients of 12 to 16 kPa/m), allowing fracture creation at treating pressures below 40 MPa within standard 70 MPa-rated pump ratings.

• DFIT design, execution, and G-function interpretation for WCSB Montney and Cardium closure pressure measurement: A WCSB diagnostic fracture injection test is designed by selecting an injection rate 20 to 50 percent above the estimated fracture extension rate for the target formation (typically 1 to 3 m3/min for WCSB Cardium and 3 to 8 m3/min for WCSB Montney), and an injection volume of 20 to 100 m3 for Cardium or 100 to 500 m3 for Montney, sufficient to create a fracture with radius of 20 to 100 m and generate a measurable pressure transient in the reservoir without creating excessive drainage volumes that would affect the main fracture treatment productivity. The G-function plot constructed from the DFIT fall-off data shows pressure versus G(delta-t), where G is a dimensionless time function that accounts for fracture geometry-dependent fluid leak-off; at fracture closure, the G-function derivative G times d-P/d-G shows a characteristic rollover from an elevated value (while the fracture is open and leak-off is fracture-face dominated) to zero (after closure when leak-off is matrix dominated), and the closure pressure is read at the point where G times d-P/d-G begins its final descent to zero. In WCSB Montney DFIT analysis, the presence of natural fractures is identified from G-function signatures showing a hump in G times d-P/d-G above the straight-line baseline (indicating pressure-dependent leak-off through natural fractures opening and closing during the test), which increases the apparent fluid efficiency and causes the DFIT to underestimate true matrix leak-off rate; analysts must identify and correct for the natural fracture signal before using DFIT permeability and efficiency data in the main fracture treatment design model.
• Net pressure, fracture width, and height containment in WCSB multistage completion design: Net pressure (treating pressure minus closure pressure) during a WCSB hydraulic fracture treatment drives fracture aperture and controls whether the fracture grows vertically into bounding formations or propagates laterally within the target pay zone. In WCSB Montney completions with closure pressure of 40 to 50 MPa and surface treating pressure of 55 to 70 MPa, net pressure at bottomhole is 15 to 25 MPa after accounting for wellbore friction and perforation friction; this net pressure generates fracture half-widths of 4 to 8 mm (from the KGD or PKN fracture width models using Montney Young's modulus of 35 to 60 GPa), sufficient to transport 40-mesh proppant at concentrations of 200 to 400 kg/m3 without proppant bridging near the perforation cluster entry points. Height containment in WCSB Montney completions depends on the stress contrast between the target Montney siltstone and the overlying Doig Phosphate or underlying Belloy formation; the stress contrast (closure pressure difference between barrier and pay) controls the net pressure threshold above which the fracture breaks through the barrier and grows vertically into non-pay intervals; typical WCSB Montney stress contrasts of 5 to 15 MPa between Montney and adjacent shale barriers provide reasonable height containment at net pressures below 20 MPa but may allow fracture height growth into the Doig or Belloy at net pressures above 20 to 25 MPa during high-rate slickwater pumping.
• Closure pressure variation across WCSB formations and its effect on fracture treatment design: Closure pressure varies significantly across WCSB formation depths and lithologies, driving distinct fracture treatment designs for each play. WCSB Viking Formation shallow oil completions at 700 to 1,200 m depth have closure pressures of 8 to 15 MPa (gradients of 11 to 14 kPa/m), allowing fracture creation with small pump equipment at treating pressures below 25 MPa and generating fractures with propped half-lengths of 50 to 100 m that are appropriate for the tight Viking sand matrix permeability of 0.1 to 2 mD. WCSB Duvernay shale completions at 3,500 to 4,200 m depth have closure pressures of 55 to 75 MPa (gradients of 16 to 18 kPa/m), requiring fracturing pumps rated to 105 MPa and specialized high-pressure surface iron (HHP iron with 105 MPa connections) to sustain treating pressures of 75 to 90 MPa needed to exceed closure and achieve net pressure for fracture propagation. WCSB Cardium gel frac completions at 1,200 to 2,000 m depth use closure pressure from DFIT to size proppant schedules: at Cardium closure of 20 to 28 MPa with treating pressures of 30 to 45 MPa, net pressure of 10 to 20 MPa sustains fracture widths adequate for 20-40 mesh sand at 400 to 600 kg/m3.
• Depletion effects on closure pressure in WCSB infill well programs and frac hit risk: Reservoir pressure depletion from production in WCSB Montney and Cardium parent wells reduces the pore pressure in the drainage area, which proportionally reduces the minimum horizontal stress and therefore closure pressure in the depleted zone through the poro-elastic coupling coefficient (alpha times (1 minus 2 nu) divided by (1 minus nu), where nu is Poisson's ratio); for typical WCSB Montney rock with nu of 0.25 and Biot coefficient alpha of 0.7, closure pressure decreases approximately 0.35 MPa for every 1 MPa of pore pressure reduction from production depletion. Infill WCSB Montney horizontal wells drilled in the depletion halo of parent wells (within 200 to 400 m laterally) encounter lower closure pressure than expected from virgin reservoir stress data, causing infill well fractures to propagate preferentially toward the low-stress depletion zone, resulting in asymmetric fracture geometry, reduced drainage of the designed infill contact area, and hydraulic communication (frac hits) with parent wells that temporarily increases parent well gas rate but permanently depletes the reservoir volume intended for the infill well. WCSB operators address infill frac hit risk by using reduced infill well fracture treating pressures designed to the depleted closure pressure, by pressure loading parent wells before infill fracturing (temporarily increasing parent wellhead pressure to raise near-wellbore effective stress), and by sequencing infill fracture stages away from parent well proximity.
• Closure pressure measurement from step-rate tests in WCSB injection wells and waterflood programs: Closure pressure in WCSB waterflood injection wells is measured by step-rate injection tests (SRTs) in which water injection rate is increased in discrete steps (each step held for 5 to 10 minutes) while monitoring wellhead injection pressure; at injection rates below the fracture extension rate, wellhead pressure increases linearly with rate (matrix injection regime governed by Darcy flow); above the fracture extension rate, wellhead pressure rise rate changes sharply as the fracture opens and fluid can be injected into a growing fracture volume at lower additional pressure. The step-rate test inflection point pressure (converted to bottomhole by adding hydrostatic head and subtracting friction) equals the fracture extension pressure, which closely approximates closure pressure in WCSB injection wells operating in normal fault stress regimes. AER Directive 051 (Injection Well Monitoring) requires WCSB waterflood injection operators to confirm that injection wellhead pressure does not exceed the fracture extension pressure during normal operations, because injecting above fracture extension pressure in WCSB waterflood programs risks uncontrolled fracture height growth out of the target Cardium or Viking formation into overlying aquifers, creating regulatory compliance failures under the Alberta EPEA groundwater protection provisions.

DFIT Closure Pressure Measurement Improving Montney Completion Design

A northeast BC Montney operator performed DFITs on the first two pilot wells before committing to the 20-well development program completion design. DFIT 1 (Well A, Montney C zone, 2,840 m TVD): injection of 180 m3 at 5 m3/min, fall-off monitored 72 hours. G-function analysis identified closure pressure at 43.2 MPa (15.2 kPa/m gradient). DFIT 2 (Well B, Montney B zone, 2,760 m TVD): 210 m3 at 5 m3/min, 60-hour fall-off. Closure pressure 41.8 MPa (15.2 kPa/m). Both DFITs showed a natural fracture hump in G times d-P/d-G indicating PDL, with corrected matrix permeability of 0.008 mD. The main fracture design was revised from 70 MPa treating pressure (assumed from regional analogue) to 62 MPa, reducing pump horsepower requirement by 18 percent. Net pressure target of 18 MPa was achievable with the revised design. The 20-well program using DFIT-calibrated closure pressure achieved average IP30 of 145,000 m3/d versus 118,000 m3/d for the 8 preceding wells designed from regional analogue data without site-specific DFITs.

Related Terms

Hydraulic fracturing treatment design in WCSB Montney, Cardium, and Viking completions is built around closure pressure; net pressure (treating pressure minus closure) determines fracture width, proppant transport capacity, and height containment in the target pay zone. Diagnostic fracture injection test (DFIT) is the standard method for measuring WCSB closure pressure before main fracture treatment; G-function analysis of the pressure fall-off identifies the closure signature and also yields matrix permeability and fluid efficiency for treatment design. Minimum horizontal stress is the geomechanical equivalent of closure pressure; in WCSB normal fault tectonic settings, sigma-h-min measured from DFIT equals closure pressure measured from fracture fall-off analysis. Net pressure (treating pressure minus closure pressure) drives fracture geometry; insufficient net pressure produces narrow fractures prone to proppant bridging in WCSB completions; excessive net pressure causes height growth into non-pay barriers. Frac hit risk in WCSB infill Montney programs is directly linked to closure pressure depletion in parent well drainage areas; reduced closure pressure in depleted zones attracts infill fractures preferentially toward parent wells.