drilling · pressure
Eaton Pore Pressure (Sonic)
PP = OBG − (OBG − Pn) × (DTn/DT)^n
click formula to derive ↑
Inputs
psi/ft
psi/ft
μs/ft
μs/ft
—
ft
Description
Predicts formation pore pressure from a sonic log by comparing observed slowness to a normal compaction trend, using the Eaton (1975) exponent method. Requires a calibrated normal trend (DTn) and overburden gradient. Widely used for pre-drill prediction and real-time geopressure monitoring while drilling.
Variables
| Symbol | Unit | Description |
|---|---|---|
| PP | psi/ft | Pore Pressure Gradient |
| PP | psi | Pore Pressure |
| EMW | lb/gal | Equivalent Mud Weight |
| OBG | psi/ft | Overburden (lithostatic) pressure gradient from an integrated bulk density log or regional model — typically 0.90-1.05 psi/ft. |
| Pn | psi/ft | Normal (hydrostatic) pore pressure gradient for the basin — typically 0.433-0.465 psi/ft depending on water salinity. |
| DTn | μs/ft | Sonic slowness expected for a normally compacted shale at this depth, read from a calibrated normal compaction trend line. |
| DT | μs/ft | Observed sonic slowness from the log at this depth. Values slower (higher) than the normal trend (DTn) indicate undercompaction and overpressure. |
| n | — | Empirical exponent in the Eaton equation. The default of 3.0 was calibrated to Gulf Coast sonic data — recalibrate to local offset wells with MDT/RFT data when possible. |
| TVD | ft | True vertical depth of the point of interest, used to convert the predicted pressure gradient into an absolute pressure and equivalent mud weight. |
Assumptions
- The normal compaction trend (DTn) has been correctly established from offset wells or regional shale trends in normally pressured sections
- The lithology is predominantly shale — the Eaton sonic method is calibrated for shale and is less reliable in sands, carbonates, or evaporites
- The Eaton exponent n is appropriate for the basin; the default n=3.0 should be recalibrated against direct pressure measurements (MDT/RFT) where available
Limitations
- Sonic-derived pore pressure is an estimate, not a measurement — always calibrate against direct pressure data (MDT, RFT, kicks, mud weight history) where available
- Gas effect, washouts, and cycle skipping on the sonic log can produce spurious slowness values that mimic overpressure
- The method assumes a single compaction mechanism (disequilibrium compaction); other overpressure mechanisms (fluid expansion, lateral transfer, hydrocarbon generation) may not follow the same DT-pressure relationship
Use Cases
- → Pre-drill pore pressure prediction: Build a pre-drill pore pressure profile from offset well sonic logs to support well planning and casing design.
- → Real-time geopressure monitoring while drilling: Continuously update the pore pressure estimate using LWD sonic data to detect developing overpressure ahead of the bit.
- → Casing seat depth selection: Identify depths where the predicted pore pressure approaches the fracture gradient to select casing setting depths.
- → Kick margin / mud weight window design: Establish the safe mud weight window between pore pressure and fracture gradient for the planned well path.
Related Calculations
Region Notes
Permian Basin
Wolfcamp and Bone Spring intervals are often only mildly overpressured (EMW 9.5-11 PPG); a normal trend DTn calibrated to the Delaware Basin shale baseline is essential before applying Eaton.
Gulf of Mexico
Classic Eaton application area — Plio-Pleistocene shales below major sand bodies frequently show EMW of 12-15 PPG, with localized overpressure cells exceeding 16 PPG near salt.
Haynesville
Severely overpressured shale gas play with EMW commonly 16-19 PPG; the default n=3.0 often under-predicts pressure here and is frequently increased to 4-5 after MDT calibration.
North Sea
Central North Sea HPHT prospects below the Chalk can show EMW >18 PPG; careful normal-trend calibration above and below major unconformities is critical.
References
Primary source
Primary source
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