Reservoir Height: Net Pay Thickness, Inflow Calculations, and WCSB Productivity Modelling

Reservoir height is the vertical thickness of reservoir formation that is open to flow, the interval of rock through which fluids can move into a wellbore and contribute to production. It is one of the fundamental geometric inputs to nearly every reservoir-engineering calculation, appearing directly in the radial inflow equations that relate flow rate to drawdown, in volumetric estimates of hydrocarbons in place, and in the analytical and numerical models used to forecast performance. The term must be used carefully because several distinct thicknesses are easily confused. Gross thickness is the total interval from the top to the base of the reservoir formation; net thickness, or net pay, is the portion of that gross interval that actually meets porosity, permeability, and saturation cutoffs and is therefore capable of flowing hydrocarbons; and the height that enters an inflow calculation is the net interval open and connected to the wellbore through perforations or an open-hole completion. In a flat-lying conventional reservoir these distinctions are modest, but in dipping beds, in deviated and horizontal wells, and in layered systems they diverge sharply, and using gross thickness where net pay is required will overstate productivity and reserves. The radial form of Darcy's law for steady-state inflow makes the dependence explicit: flow rate scales linearly with the product of permeability and reservoir height, so a doubling of net pay doubles deliverability at a given drawdown, all else equal. This is why net pay mapping is among the most scrutinized deliverables in any development study. In the Western Canadian Sedimentary Basin (WCSB), reservoir height is interpreted from wireline logs calibrated to core, with gamma ray, neutron-density porosity, and resistivity curves used to flag the net interval above cutoffs, then summed across the perforated or stimulated zone. Conventional pools such as the Cardium at Pembina or the Viking are mapped as net-pay isopachs that guide well placement and reserves bookings under National Instrument 51-101. Unconventional plays complicate the picture: in the Montney and Duvernay, where a horizontal lateral with a multi-stage hydraulic fracture contacts the rock, the relevant "height" shifts from a simple open interval to the effective fracture height that connects the stimulated rock volume to the well, a quantity inferred from microseismic, pressure transient analysis, and fracture modelling rather than read directly off a log. Reservoir height also constrains the position of fluid contacts and the gas or oil column available, so it interacts with capillary pressure, the transition zone, and the structural relief of the trap. Reported in metres in Canadian practice and in feet in much US and legacy literature, reservoir height is a deceptively simple measurement whose correct definition for the question at hand determines whether a forecast or a volumetric estimate is sound.

Net Pay Cutoffs and How Height Is Summed

Net pay is built by applying cutoffs to the logged interval: a porosity floor, a permeability or volume-of-shale limit, and a water-saturation ceiling. Footage that clears all three is summed to net height; footage that fails any one is excluded. In a Viking sand at Provost, an analyst might use a 10 percent porosity cutoff, a 50 percent shale cutoff, and a 50 percent Sw ceiling, yielding perhaps 4 m of net pay within a 9 m gross sand. That 4 m, not the 9 m, is the height that belongs in the inflow equation and the volumetric calculation, and the choice of cutoffs is documented because it directly moves the reserves number.

Effective Height in Horizontal and Fractured Wells

When a well is horizontal, the classic vertical-well radial inflow no longer applies and reservoir height enters through fracture geometry instead. In a Montney development, the production-controlling dimension is the effective propped fracture height that connects the reservoir to the lateral, often a fraction of the gross formation thickness because fractures can be contained by stress barriers or bounding shales. Pressure transient tests and microseismic clouds are used to estimate this contacted height, which then feeds rate-transient and reservoir-simulation models that forecast estimated ultimate recovery for the well.

Related Terms

Reservoir height is the net portion of net pay, the footage left after porosity, permeability, and saturation cutoffs are applied to the logged section. It is a direct multiplier in the inflow relationship governed by permeability, since flow rate scales with the product of the two. The interval is interpreted from porosity and resistivity logs, and it constrains the hydrocarbon column available within the trapping structure.

Real-World WCSB Scenario: Cardium Net-Pay Revision at Pembina

An operator evaluating a Cardium infill at Pembina initially mapped 7 m of gross sand and modelled deliverability on that figure, projecting an initial rate that justified an 8 million CAD horizontal well. A petrophysical review applied a 9 percent porosity cutoff and a 55 percent Sw ceiling and resolved only 3.2 m of true net pay, with the upper sand wet.

Rerunning the inflow model on 3.2 m cut the forecast initial rate by more than half and pushed the well below the economic threshold at the prevailing strip price. The team relocated the lateral updip into a thicker net-pay fairway identified on the revised isopach, preserving project economics and avoiding a likely uneconomic completion.