bottomhole shut-in

Bottomhole shut-in pressure in pressure transient analysis provides the foundational measurement from which WCSB reservoir engineers extract formation permeability, skin factor, initial reservoir pressure, and drainage area in conventional and tight oil and gas wells by recording how the bottomhole pressure rises after the well is shut in at surface and mathematically analyzing the pressure buildup curve to separate the contributions of reservoir transmissibility, wellbore storage, and near-wellbore damage or stimulation to the observed transient response. The pressure buildup test (PBU) in WCSB Montney, Viking, Cardium, and Duvernay wells uses a downhole pressure gauge placed as close as possible to the producing interval to measure the actual bottomhole shut-in pressure (BHSIP) as a function of shut-in time, avoiding the wellbore fluid column pressure correction errors that arise when surface shut-in pressure is converted to bottomhole equivalent, particularly in WCSB gas wells where the static fluid column composition and temperature gradient change after shut-in as the wellbore cools and liquid condensate redistributes in the tubing string. The classic Horner plot analysis of a WCSB pressure buildup test plots BHSIP on the y-axis against the Horner time ratio log((tp + delta_t)/delta_t) on the x-axis, where tp is the producing time before shut-in in hours and delta_t is the elapsed shut-in time in hours; the slope m of the straight-line portion of the Horner plot in kPa/log-cycle is related to formation permeability k by the relation k = 21.5 x Q x mu x B / (m x h), where Q is the production rate in m3/day, mu is the formation fluid viscosity in mPa.s, B is the formation volume factor, and h is the net pay thickness in metres, allowing the WCSB reservoir engineer to calculate reservoir permeability directly from the shut-in pressure buildup gradient without core plug measurements. In WCSB tight formations such as the Montney siltstone and Duvernay shale where matrix permeability ranges from 0.001 to 0.1 millidarcies, pressure buildup tests after hydraulic fracturing measure the effective permeability of the stimulated reservoir volume rather than the matrix permeability alone, and the Horner straight line appears only after the test has been run for sufficient time for the fracture transient (linear flow regime) to transition to radial flow, which may require shut-in times of 50 to 500 hours in tight formations; WCSB operators designing pressure buildup tests in Montney horizontal wells must anticipate these long shut-in requirements and the associated deferred production cost when scheduling buildup tests to obtain the formation transmissibility data needed for well performance forecasting and reserve estimation. Understanding Horner plot analysis methodology for WCSB conventional and tight reservoir characterization, skin factor calculation from the pressure intercept at Horner time ratio equal to one, wellbore storage identification from the early-time unit-slope log-log pressure derivative, the distinction between matrix permeability and fracture-dominated transmissibility in WCSB hydraulically fractured wells, and how extrapolated initial reservoir pressure from the Horner plot compares to DFIT-derived minimum horizontal stress gives WCSB reservoir engineers, production engineers, and reservoir development teams the pressure transient analysis framework to characterize reservoir quality and completion effectiveness from BHSIP buildup data.

• Horner plot analysis for WCSB Viking oil well permeability and skin determination: A WCSB Viking tight oil well in west-central Alberta producing at 25 m3/day (oil, Bo = 1.15, mu = 2.8 mPa.s) from a 6 m net pay interval was shut in for a 96-hour pressure buildup test after 480 hours of production (tp = 480 hours). The Horner plot of the downhole gauge data showed a straight line with slope m = 680 kPa/log-cycle over the Horner time ratio range of 2.0 to 50, corresponding to formation permeability k = 21.5 x 25 x 2.8 x 1.15 / (680 x 6) = 0.042 mD. The pressure intercept at Horner time ratio of 1.0 (representing infinite shut-in time, i.e., initial pressure) extrapolated to 18,400 kPa; the actual BHSIP at shut-in time of 96 hours was 17,920 kPa. The skin factor s calculated from the Horner equation s = 1.151 x [(P1hr - Pwf) / m - log(k / (phi x mu x ct x rw2)) + 3.23] gave s = minus 3.2, indicating effective hydraulic fracture stimulation that extended the effective wellbore radius beyond the physical bit size.
• Wellbore storage distortion of early BHSIP buildup data in WCSB gas wells: Wellbore storage in WCSB gas wells distorts the early portion of the BHSIP buildup curve by masking the formation transient response with the pressure effect of gas expansion within the wellbore after shut-in: when a WCSB Cardium gas well is shut in, the high-pressure wellbore gas expands and continues to flow into the wellbore from the reservoir for a period controlled by the wellbore volume and the formation transmissibility, delaying the onset of the straight-line Horner region. The wellbore storage coefficient C (m3/kPa) for a WCSB gas well is approximately 0.004 x Vw / P, where Vw is the wellbore volume in m3 and P is the average wellbore pressure in MPa; for a 3,500 m deep Cardium gas well with 4.5-inch tubing (Vw approximately 14 m3) at 15 MPa average wellbore pressure, C is approximately 0.0037 m3/kPa. The end of wellbore storage distortion on the log-log derivative plot is identified where the derivative departs from the unit slope (45-degree) early-time line; in WCSB Cardium gas wells this transition occurs at shut-in times of 3 to 12 hours, meaning Horner analysis requires that the first 3 to 12 hours of buildup data are excluded from the straight-line fit to avoid permeability underestimation from wellbore storage masking.
• Extended pressure buildup tests in WCSB Montney tight gas for linear-to-radial flow regime identification: WCSB Montney horizontal wells with hydraulic fractures require extended shut-in times to achieve the radial flow regime required for Horner plot permeability analysis because the fracture transient (bilinear and linear flow) persists for tens to hundreds of hours before the transient reaches the matrix beyond the fracture half-length. In a WCSB Montney horizontal well with 40 hydraulic fractures at 60 m stage spacing and estimated fracture half-length of 80 m, the linear flow regime (pressure proportional to square root of shut-in time) persists until delta_t = phi x mu x ct x xf2 / (0.000264 x k), where xf is fracture half-length and k is matrix permeability; at xf = 80 m and k = 0.005 mD, linear flow persists for approximately 180 hours before transitioning to compound linear flow and eventually pseudo-radial flow at 600 to 2,000 hours. WCSB operators must weigh the value of the Horner-derived permeability against the deferred production cost of a 600-hour shut-in (25 days at initial rates of 100 to 300 Mscf/day, equivalent to $15,000 to $45,000 in deferred revenue at $1.50/Mscf) when designing Montney pressure buildup test programs.
• Downhole gauge placement and BHSIP data quality in WCSB horizontal well buildup tests: BHSIP buildup data quality in WCSB horizontal wells depends critically on placing the downhole pressure gauge within 200 to 400 m of the producing interval so that the measured pressure accurately represents formation pressure rather than the midpoint of a multi-kilometer wellbore fluid column. WCSB Montney horizontal wells with 2,000 to 3,000 m laterals use coiled tubing-conveyed gauges set at the heel of the lateral or memory gauges deployed on the production packer; a gauge placed at the surface-casing shoe (800 m depth) in a 4,200 m TVD Montney well requires a hydrostatic correction of 3,400 m x 0.85 kg/L x 0.00981 MPa/(m x kg/L) = 28.3 MPa, with the composition and temperature of the 3,400 m fluid column changing during shut-in as the well cools, introducing pressure correction errors of 0.5 to 1.5 MPa that corrupt the late-time Horner straight line and produce permeability errors of 15 to 40%. Direct bottomhole gauge measurement eliminates this correction entirely and is the standard specification for WCSB Montney and Duvernay pressure buildup tests used for reserve certification.
• Initial reservoir pressure determination from Horner extrapolation and its use in WCSB material balance: The Horner plot extrapolation to infinite shut-in time (Horner time ratio of 1.0) gives the initial reservoir pressure Pi (or current average reservoir pressure P-bar if the well has been on production long enough to deplete the drainage area). In WCSB conventional Cardium and Viking oil pools, Pi determined from Horner buildup tests at multiple wells across the pool defines the initial pressure surface used in volumetric material balance calculations to estimate original oil in place; pressure depletion between the initial Pi and the current P-bar at each well location measures the produced reservoir voidage and, combined with production data, gives a volumetric hydrocarbon pore volume estimate that the WCSB engineer compares against the geological volumetric estimate for consistency. For WCSB Montney and Duvernay tight gas wells where reservoir depletion is spatially non-uniform due to fracture-dominated drainage, the Horner-derived P-bar at each well represents the average pressure within that well's drainage area rather than a pool-wide pressure, and material balance is applied on a well-by-well basis using dynamic drainage area estimated from production decline analysis.

Horner Buildup Analysis Confirming Fracture Stimulation Effectiveness on a WCSB Cardium Horizontal

A west-central Alberta Cardium horizontal oil well was shut in for a 72-hour pressure buildup test after 30 days of production at an average rate of 38 m3/day. A memory gauge set on the production packer at 2,140 m measured depth recorded the BHSIP buildup from initial shut-in pressure of 14,820 kPa to a 72-hour BHSIP of 18,240 kPa. The Horner plot over the 72-hour test showed a straight-line segment from 12 to 60 hours (Horner time ratio 43 to 3) with slope m = 920 kPa/log-cycle. Permeability calculated as k = 21.5 x 38 x 1.6 x 1.08 / (920 x 8) = 0.019 mD was consistent with core plug measurements of 0.012 to 0.025 mD from the nearby vertical pilot well. Skin factor calculated from the 1-hour BHSIP of 16,150 kPa gave s = minus 4.8, confirming effective hydraulic fracturing with an apparent effective wellbore radius of 6.5 m. Extrapolating the Horner straight line to a time ratio of 1.0 gave Pi = 19,700 kPa, compared to the DST-derived initial pressure of 19,450 kPa from the vertical pilot, confirming pressure communication with the natural Cardium pool. The 72-hour buildup test cost 72 hours of deferred production (approximately 114 m3 at 38 m3/day) but provided a fully characterized reservoir description that supported a 30-well horizontal development program.

Related Terms

Bottomhole shut-in pressure is the primary entry covering BHSIP in well control and DFIT interpretation; this companion entry covers BHSIP in pressure transient analysis, where Horner plot buildup analysis of the shut-in pressure rise yields formation permeability, skin factor, and initial reservoir pressure for WCSB reservoir characterization and reserve estimation. Horner plot is the primary analytical tool for WCSB pressure buildup test interpretation; the slope of the Horner straight line converts directly to formation transmissibility, and the pressure intercept at unit Horner time ratio gives initial reservoir pressure for material balance input in WCSB conventional and tight oil and gas wells. Skin factor is the dimensionless near-wellbore damage or stimulation indicator derived from Horner buildup analysis; negative skin in WCSB hydraulically fractured Montney and Cardium wells confirms fracture effectiveness, while positive skin identifies near-wellbore damage requiring remediation. Wellbore storage is the early-time distortion of BHSIP buildup data caused by expanding wellbore fluids after shut-in; unit-slope identification on the log-log pressure derivative plot determines when wellbore storage ends and the Horner straight line begins in WCSB pressure buildup test analysis. Pressure transient analysis is the reservoir engineering discipline that interprets BHSIP buildup and drawdown data; Horner plot, log-log derivative, and type-curve matching collectively characterize reservoir permeability, fracture geometry, and boundary conditions from WCSB well test data.