Fracture Gradient Estimator

Estimate formation fracture pressure using Matthews-Kelly, Eaton, or Hubbert-Willis methods. Calculate safe mud weight windows for drilling operations and visualize pressure regimes to prevent lost circulation and formation damage.

Drilling Pore Pressure Geomechanics Wellbore Stability

Input Parameters

Calculation Method

Most commonly used method worldwide

Depth

ft
True vertical depth subsea or below rotary table

Pressure Parameters

psi
Formation pore pressure at depth
psi/ft
Typically 1.0 psi/ft (0.023 MPa/m)

Rock Properties

dimensionless
Typical range: 0.20 - 0.35

Safety Margins

ppg
Safety margin above pore pressure
ppg
Safety margin below fracture gradient

Results

Theory & References

Matthews-Kelly Method

FP = (σv - PP) × K + PP

K = ν / (1 - ν)

Where:

  • FP = Fracture pressure
  • σv = Overburden stress
  • PP = Pore pressure
  • ν = Poisson's ratio
  • K = Stress ratio coefficient

Applications:

Most widely used method worldwide. Assumes fracture occurs when effective horizontal stress exceeds rock tensile strength. Best for clastic sediments in normal to slightly overpressured regimes.

Eaton Method

FP = (σv / D) × K + PP × (2ν / (1 - ν))

K = ν / (1 - ν)

Applications:

Developed for Gulf Coast conditions. Accounts for depth-dependent stress state and is more conservative in overpressured zones. Commonly used in deepwater and high-pressure environments.

Key Differences:

  • Depth-normalized overburden stress
  • Modified pore pressure contribution
  • Generally predicts lower fracture gradients

Hubbert-Willis Method

σmin = K × (σv - α × PP) + α × PP

K = ν / (1 - ν)

Where:

  • σmin = Minimum horizontal stress (fracture pressure)
  • α = Biot coefficient (effective stress)

Applications:

Incorporates effective stress concept with Biot coefficient. Useful for consolidated rocks where pore pressure coupling is not perfect (α < 1). Common in hard rock and tight formations.

Mud Weight Window

Safe Operating Window:

PP + Safety Margin < MW < FP - Safety Margin

Critical Considerations:

  • Lower Limit: Must exceed pore pressure to prevent kicks
  • Upper Limit: Must stay below fracture to prevent losses
  • Safety Margins: 0.3-0.5 ppg typical, higher for uncertainty
  • Narrow Windows: Require managed pressure drilling (MPD)

Window Quality Classification:

  • Excellent: > 3.0 ppg - conventional drilling
  • Good: 2.0-3.0 ppg - careful control needed
  • Fair: 1.0-2.0 ppg - consider MPD
  • Narrow: 0.5-1.0 ppg - MPD recommended
  • Critical: < 0.5 ppg - MPD or casing required

Typical Poisson's Ratios

Sandstone: 0.20 - 0.30
Shale: 0.28 - 0.35
Limestone: 0.25 - 0.30
Dolomite: 0.24 - 0.28
Salt: 0.35 - 0.40
Coal: 0.30 - 0.40

Notes:

  • Higher Poisson's ratio → higher fracture gradient
  • Use log-derived or lab measurements when available
  • Temperature and pressure affect values

References & Standards

  • Matthews, W.R., and Kelly, J., 1967, "How to Predict Formation Pressure and Fracture Gradient," Oil & Gas Journal
  • Eaton, B.A., 1969, "Fracture Gradient Prediction and Its Application in Oilfield Operations," JPT
  • Hubbert, M.K., and Willis, D.G., 1957, "Mechanics of Hydraulic Fracturing," AIME Transactions
  • Zhang, J., 2013, "Applied Petroleum Geomechanics," Elsevier
  • Zoback, M.D., 2007, "Reservoir Geomechanics," Cambridge University Press
  • API RP 13D - Rheology and Hydraulics of Oil-well Drilling Fluids
  • IADC Drilling Manual (12th Edition)