petrophysics · net pay
Flow Capacity and Storage Capacity
kh = k_avg × h_net | φh = φ_avg × h_net | FQI = kh / φh
click formula to derive ↑
Inputs
mD
fraction
ft
Description
Flow capacity (kh) and storage capacity (φh) are the fundamental interval-scale metrics used in well test interpretation, productivity index (PI) calculations, and reservoir simulation. FQI (flow quality index = k/φ) is a unitless measure of how well the pore network transmits fluids relative to the volume available, providing a quick comparison between intervals and wells.
Variables
| Symbol | Unit | Description |
|---|---|---|
| kh | mD·ft | Flow Capacity |
| φh | fraction·ft | Storage Capacity |
| FQI | mD/fraction | Flow Quality Index |
| k̄ | mD | Arithmetic average permeability of the net pay interval, from core measurements or a permeability transform applied to the log. In laminated reservoirs use harmonic mean for vertical flow; arithmetic for lateral/horizontal flow. |
| φ̄ | fraction | Average effective porosity of the net pay interval, from the porosity log corrected for shale effects. |
| h | ft | Net pay thickness in meters (canonical). In imperial display: convert ft to m before calculation. Derived from the net pay cutoff calculation applied to the petrophysical logs. |
Assumptions
- Net pay interval is vertically continuous and can be represented by a single k_avg and φ_avg — layered reservoirs should use layer-by-layer kh and sum
- h_net is derived from a consistent set of net pay cutoffs applied to the same well
Limitations
- Arithmetic average k is appropriate for lateral flow only; layered vertical flow needs harmonic mean — always report which averaging method was used
- kh from logs is a static estimate; actual well productivity also depends on damage (skin), relative permeability to oil/gas, and stimulation effectiveness
Use Cases
- → Pre-drill PI estimate for well economics: Use log-based kh with anticipated fluid properties and wellbore geometry to estimate PI before drilling, allowing early decision on whether a well needs stimulation and what rate to use in economics.
- → Well test interpretation crosscheck: Compare log-derived kh against well-test kh (from pressure derivative analysis); a factor-of-2–5 difference is normal; larger discrepancies suggest damage, partial penetration, or barriers not seen on logs.
- → Interval ranking in multi-zone reservoirs: Sum kh and φh for each zone separately; the ratio (kh zone / kh total) tells you each zone's contribution to well productivity, guiding perforation selection in mixed reservoirs.
Related Calculations
Region Notes
Permian Basin
Wolfcamp tight oil: kh 0.1–5 mD·m in unstimulated intervals; hydraulic fracturing effectively multiplies kh by 10–100×. FQI typically 0.05–2 mD/fraction — consistent with sub-commercial matrix flow.
Delaware Basin
Bone Spring: kh 1–20 mD·m in productive sands; FQI 5–50 mD/fraction; intervals with FQI > 20 and kh > 5 mD·m are the primary hydraulic fracture targets.
Gulf of Mexico
GOM Miocene/Pliocene: kh 500–50,000 mD·m in major sand bodies; FQI 500–5000 mD/fraction. PI values of 5–30 STB/d/psi routinely achieved without stimulation.
Eagle Ford
Matrix kh < 0.01 mD·m in tight oil window; all production relies on fracture kh. FQI 0.001–0.05 mD/fraction matrix only — use stimulated reservoir volume (SRV) k for production estimates.
Haynesville
Gas shale: matrix kh < 0.001 mD·m; FQI < 0.05 mD/fraction. Hydraulic fracture half-length and conductivity dominate; log-derived kh is used only to calibrate fracture-reservoir models.
Global
Rule of thumb for unstimulated wells: kh > 100 mD·m = good well without stimulation; kh 10–100 = needs stimulation; kh < 10 = requires extensive hydraulic fracturing or horizontal drilling to be economic.
References
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