Fluid Pressure in a Cap Rock
1. How do we generally ensure (in a real field scenario)
that the fluid pressure in a cap rock or seal
(associated with a typical petroleum reservoir)
remains always greater than
the reservoir fluid pressure
so that the escape of (reservoir) hydrocarbons
through this cap rock
remains prevented –
throughout the production life?
Pressure in a cap-rock
will always be greater
than the gas-pressure
(and in turn, greater than oil-pressure;
and in turn, greater than the water-pressure)?
2. During hydrocarbon production, to what extent,
‘the pore-sizes of cap rock or seal get disturbed’
in terms of ‘reservoir heterogeneity’?
Whether the oil and/or gas
that keep accumulating in cap rock or seals
would be able to displace the water
from the pores (at some point of time)?
What is the surety that the produced bound water film thickness
(by capillary force, fluid wettability and the attraction between fluid and solid molecules) in a cap rock or seal –
would not exceed
the critical/mean pore-size of cap rock or seals;
and in turn,
the hydrocarbons that got released from reservoirs,
and eventually, got accumulated in cap rocks or seals
would be completely prevented,
escaping from cap-rock or seals?
3. How easy would it remain
to deduce the boundaries between
effective reservoirs and cap-rock/seals (non-reservoirs)?
Whether the reservoir boundaries
with the lower porosity and permeability
can also be delineated with ease?
4. How easy would it remain
to estimate the critical flow pore diameter as a function of
(a) mechanical balance of oil and gas filling;
(b) reservoir mineral composition;
(c) reservoir pore structure;
(d) bound water saturation;
(e) rock specific surface area; and
(f) rock density?
5. Whether the estimation of ‘critical flow pore diameter’
using ‘Young-Laplace equation’
based on the assumption that
‘the resistive and dynamic forces
remain to be equal when oil and gas filling remains balanced’ –
would remain valid under all circumstances?
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