reservoir · volumetrics
Gas in Place (GIIP)
GIIP = (43560 × A × h × φ × (1−Sw)) / Bg
click formula to derive ↑
Inputs
acres
ft
fraction
fraction
ft³/scf
Description
Estimates the original gas in place using the standard volumetric equation — drainage area times net pay times porosity times gas saturation, converted from reservoir to standard (surface) conditions via the gas formation volume factor. The foundation for shale gas and conventional gas resource assessment.
Variables
| Symbol | Unit | Description |
|---|---|---|
| GIIP | scf | Gas in Place |
| A | acres | Areal extent of the drainage area or reservoir compartment. 259 ha (≈640 acres / 1 section) is a common single-well drainage assumption for unconventional spacing. |
| h | ft | Net (reservoir-quality, gas-bearing) pay thickness after applying porosity/Sw/Vcl cutoffs. |
| φ | fraction | Average effective porosity of the net pay interval — a thickness-weighted average from log analysis. |
| Sw | fraction | Average water saturation of the net pay interval. (1−Sw) gives the gas saturation used in the volumetric calculation. |
| Bg | ft³/scf | Gas formation volume factor — reservoir volume per standard volume at reservoir T and P. Lower Bg corresponds to higher reservoir pressure. Use a z-factor-corrected value from PVT analysis. |
Assumptions
- Porosity, Sw, and net pay are representative averages of the drainage area, not just the wellbore
- Bg is representative of the reservoir gas at initial reservoir pressure and temperature, including z-factor effects
- Drainage area and net pay are reasonably well constrained by seismic, offset wells, or analogy
Limitations
- Does not account for recovery factor — typical gas recovery factors are higher than oil (50-80% for conventional, lower for shale) and must be applied separately
- For unconventional reservoirs, adsorbed gas (especially in organic-rich shales) is not captured by this free-gas volumetric equation and may need to be added separately
- Sensitive to Bg, which depends on reservoir pressure — using a surface or wrong-pressure Bg significantly biases the result
Use Cases
- → Shale gas resource estimation: Estimate free gas in place per well or per section as an input to EUR and type-curve calibration in unconventional plays.
- → Conventional gas volumetrics: First-pass estimate of gas reserves for a conventional reservoir prior to dynamic modeling.
- → EUR calibration: Compare volumetric GIIP against EUR from decline curve analysis to sanity-check recovery factor assumptions.
Related Calculations
Region Notes
Haynesville
High-pressure (>10,000 psi), high-temperature shale gas: Bg is low (~0.003-0.005 ft³/scf) due to high reservoir pressure; adsorbed gas is a minor fraction of total gas in place compared to lower-pressure shales.
Permian Basin
Wolfcamp/Bone Spring gas-condensate intervals: Bg typically 0.004-0.008 ft³/scf depending on depth and pressure depletion stage.
Appalachian Basin
Marcellus shale: lower reservoir pressures than Haynesville give Bg≈0.006-0.010 ft³/scf, and adsorbed gas can be a significant fraction (10-30%) of total GIIP — consider a separate adsorption (Langmuir) term.
Global
Always verify whether Bg was computed at initial reservoir pressure or current (depleted) pressure — using a depleted-pressure Bg in an OOIP-style "in place" calculation will understate the original gas in place.
References
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