Suppose we have to inject CO2 within a deep geological formation, we have overburden and pore pressures given. How do we decide the maximum pressure which the formation can allow to rise without leading to formation failure?
You have to keep in mind three pressure gradients (how pressure varies with depth, below the chosen elevation datum), namely:
- the normal hydrostatic gradient (as a first approximation, 1 kg/cm2 every 10 meters of depth, assuming water density = 1 g/cm3);
- the formation or pore pressure gradient (the formation pressure is measured in a well, and you need to know which is the pore fluid at the point of measure, usually water);
- the overburden gradient (in practice, calculated from the density of the rock layers above your target reservoir rock).
The formation pore pressure could be falling on the normal hydrostatic gradient (in this case the formation is normally pressured), or above it (in this case the formation is said to be overpressured).
The key piece of information comes from a special measure which is done usually as soon as the well drills out of a casing shoe, which is the "Leak-Off Test" (LOT). The LOT serves to understand the pressure at which the formation is fracked by pressure (fails), and therefore to know which mud density (taking in consideration also fluid friction and the like) should not be exceeded if the driller wants to avoid mud losses during drilling due to formation failure.
The leak-off pressure (and gradient) represents the pressure that should not be exceeded during CO2 injection, to avoid cover rock failure by rupturing.
Usually, in extensional regimes (areas with normal, not reverse, faults), the leak-off pressure is approximately 60% to 80% above the normal hydrostatic gradient, depending on the stress status of the rocks and their strenght, and below the overburden gradient.
In natural gas underground storage (UGS), there are accepted standards (UNI norms, and British Standards) that indicate that the storage pressure should not exceed 30% to 70% of the normal hydrostatic gradient, in order to keep the storage pore pressure way below the leak-off or frac gradient (see attached file).
If a reservoir formation is overpressured (see above), there is less safety margin before reaching rock failure (leak-off, or frac gradient), and this makes overpressured reservoirs worse candidate for CO2 storage than normally pressured reservoirs of similar quality.
Besides, overpressured reservoirs usually are such because they are more or less completely isolated hydraulically from other reservoir rocks, and this too limits very much their capacity for CO2 storage, because displaced water cannot leave the reservoir where CO2 is injected.
the storage pressure should not exceed 30% to 70% of the normal hydrostatic gradient above the hydrostatic gradient (i.e. not reach 130% to 170% of the hydrostatic pressure)
You may find some answer in the attached puplicaion
Article Integration of Pore Pressure/Fracture Gradient Prediction Me...
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