Reservoir Engineering
1. Under reservoir compartmentalization, how easy would it remain to deduce the ‘depth of free water level’ (where, buoyancy pressure remains zero in a reservoir-aquifer system; and that defines the down-dip limits of an accumulation); where, the ‘hydrocarbon pressure gradient line’ intersects with the ‘hydrostatic pressure gradient line’?
Whether a simple projection of RFT pressure data from a reservoir to the aquifer would suffice?
Under reservoir compartmentalization, whether the determination of ‘free water level’ using ‘a single pressure buildup point in the reservoir’ would remain justified – towards determining the ‘down-dip length of hydrocarbon column’ as a function of ‘buoyancy pressure’ (difference between the ‘measured pressure’ and ‘hydrostatic pressure’ @ given depth) and ‘buoyancy pressure gradient’ (difference between hydrostatic and hydrocarbon pressure gradients)?
2. Since, ‘density of oil’ in a petroleum reservoir depends on reservoir pressure, reservoir temperature, ‘amount of dissolved gases’ along with its ‘chemical composition’; how exactly, are we supposed to consider the role of ‘fluid density’ in a typical oil-water-gas system, while applying the fundamental ‘mass conservation’ equation?
And, in case of a gas reservoir, ‘density of gas’ remains to be dependent on the ratio of its ‘mass’ to its ‘volume’; where, the ‘mass’ remains related to ‘the apparent molecular weight of the gas’, while its ‘volume’ remains related to ‘reservoir pressure’, ‘reservoir temperature’ and ‘the apparent molecular weight of the gas’. And, if so, whether, introducing ‘fluid compressibility’ using a simple chain rule would suffice?
And, how do we deduce the ‘apparent molecular weight of the gas mixture’ (as a function of ‘mole fraction of a component of the mixture’ and ‘the molecular weight of a component of the mixture’), if we do not have sufficient data on both ‘gas composition’ and ‘the formation temperature’ – associated with a gas reservoir? And in such cases, to what extent, ‘pseudo-reduced pressure and temperature’ would help us in deducing the ‘gas compressibility factor’?
3. Feasible to correlate ‘reservoir pressure’ as a function of ‘buoyant forces’ (which causes the lighter fluids such as gas and oil to be positioned in the higher position of the reservoir); and ‘capillary forces’ (which causes the intrusion of the wetting fluid such as water by capillary rise into the pore-space occupied by the non-wetting fluid) that essentially control the fluid distribution within the reservoirs?
4. How easy would it remain to have a control over the ‘oil and connate-water pressure regimes’, when the ‘thickness of the transition-zone’ remains ‘significantly larger’ such as that found in ‘low-permeable carbonate reservoirs’ (nearly 100 m)?
Hi Suresh -
We can always ask a lot of complicated questions to the fluid pressure and hydrocarbon saturation distribution in a hydrocarbon reservoir. In the classical model, which I think is in the back of your mind, hydrocarbons have entered a waterwet porespace below a seal and pushed the HCWC downwards when filling the reservoir in a capillary drainage process in complete equilibrium and where the hydrocarbons and water has constant properties and are in hydrostatic equilibrium. In those cases the hydrocarbon distribution will be defined by a flat/horizontal FWL and a capillary drainage type saturation-height-model with constant fluid gradients.
But in reality things are more complex. Hydrocarbons can only enter a reservoir by flowing into the reservoir by a pressure gradient, water above the FWL during the filling of the reservoir can only escape sideways/downwards if there exist a pressure gradient in the water and vertical/horizontal mixing of different water/hydrocarbon types entering/escaping a reservoir during the filling process will require typically more than geological time to fully mix and homogenize in the reservoir. Finally, any reservoir has typically been buried after the migration causing porosity to reduce and the stop of any migration of hydrocarbons into the reservoir has changed any lateral migration pressure gradient in the hydrocarbon phase and changed areas/volumes in drainage to be in imbibition.
Having worked with large lowperm reservoirs the last 30+years I have come to the conclusion that no large low perm reservoirs are in true drainage capillary equilibrium as they always in some way will be affected by the dipping contacts during migration, the time it take to fully homogenize variations in hydrocarbon type during migration, the time it take to squeeze the water out from the low water saturation zones in the crestal positions, the effect of further burial including the compression of gas caps etc.
So in reality - no large hydrocarbon reservoir are in true capillary drainage equilibrium with constant hydrostatic fluid gradients or flat/horizontal FWLs. That does of course not implicate that we cannot model a given reservoir using drainage capillary equilibrium as an assumption, but it requires that some simple BOE has been made to establish that the result of the migration process for the reservoir is not deviating too much from the standard assumption.
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