The Fracture Gradient
Learning objectives
- Define the fracture gradient as the pressure at which the formation takes a fracture, the drilling ceiling
- Distinguish losing mud into a fracture from making a fracture on purpose
- Compare the estimation methods honestly, Hubbert-Willis, Matthews-Kelly, and the measured value
- Evaluate the canon Hubbert-Willis estimate, 42.8 MPa, against the measured Shmin of 46
The Ceiling on Pressure
The mud-weight window of Part 6 had an upper bound: the pressure at which the rock fractures and takes fluid. Expressed as a gradient, that ceiling is the fracture gradient, and it is the single most important number a drilling engineer needs above the pore pressure, because it caps how heavy the mud can be and how hard any fluid can be pumped. There is a useful ambiguity in the word. Drilling tries not to reach it, staying below to avoid losing circulation; stimulation deliberately exceeds it, pumping past to open a fracture and produce through. Same number, opposite intent, which is why this section bridges the wellbore of Part 6 to the hydraulic fracturing of the sections to come.
To first order the fracture gradient is the minimum horizontal stress , because a fracture opens against the least stress, which is exactly what the leak-off tests of Part 5.4 measure. But before those tests are run, or where they are unavailable, the gradient must be estimated, and several methods compete. The oldest, Hubbert-Willis, assumes the least stress is a fixed fraction of the effective overburden: . Others, like Matthews-Kelly and Eaton, use a depth-varying or Poisson-based coefficient instead of the fixed one third.
The figure plots the methods against depth and lets you compare them with the measured value. For the canon well, Hubbert-Willis gives MPa at hydrostatic pore pressure, a little below the measured of 46 MPa. That gap is honest and instructive: the fixed-one-third assumption under-predicts in a basin whose horizontal stress sits above the elastic minimum, exactly the point section 2.3 made about K0. The methods are screening tools, not substitutes for a real leak-off test, and a good drilling plan uses them to bracket the gradient before drilling and then updates to the measured value the moment a test is run.
Why It Rises, and Why It Can Fall
The fracture gradient generally increases with depth, because does, which is why deeper sections tolerate heavier mud, but it does not increase uniformly. In an overpressured interval the gradient rises faster, because the elevated pore pressure lifts the total horizontal stress with it, the very effect that pinches the mud window. And once a field is produced, the fracture gradient falls, because depletion lowers along the stress path of section 2.6, at two thirds of the pore-pressure drop. So infill wells drilled into a depleted reservoir fracture at lower pressures than the discovery well did, a fact Part 10 turns into the frac-hit problem. The fracture gradient is not a fixed property of the rock but a live number that tracks the stress state, and the next sections watch what happens when a well pushes past it on purpose.
References
- Hubbert, M. K., & Willis, D. G. (1957). Mechanics of hydraulic fracturing. Transactions of the AIME, 210, 153-168.
- Matthews, W. R., & Kelly, J. (1967). How to predict formation pressure and fracture gradient. Oil and Gas Journal, 65(8), 92-106.
- Zoback, M. D. (2007). Reservoir Geomechanics. Cambridge University Press.