Reservoir Engineering: Relative Permeability
1. Would it remain feasible to estimate
a single-valued,
flow-rate independent
steady-state ‘drainage relative permeability’
(or ‘characteristic relative permeability’)
@ core-scale
using experimental investigations
as a function of pressure drop and flow rate?
2. Does saturation gradient exist
along the core during the measurement?
If so, does it result
only from a capillary discontinuity
that exists @ core outlet boundary?
3. Also, does “non-linear” phase pressure gradients exist?
If so, by default, can we correlate the same with ‘end effect’?
4. What is the fraction of flow rate dependency of (effective) relative permeability
attributed to
(a) non-uniform saturation; and
(b) non-linear phase pressure gradients?
5. Do we have something called a ‘homogeneous core’ @ core-scale?
If not, how do we ensure
that a given core
@ laboratory-scale
has NOT influenced
both
(a) flow behavior; and
(b) fluid retention
@ laboratory-scale?
6. If the magnitude of relative permeability
gets influenced by physical heterogeneity, then,
whether,
both the phases of relative permeability
would get decreased/increased?
And, to what extent, the magnitudes of relative permeability
is expected to vary
(a) when the primary heterogeneity of the core
remains aligned ‘parallel’ to fluid flow injection? &
(b) when the primary heterogeneity of the core
remains aligned ‘perpendicular’ to fluid flow injection?
7. Feasible to characterize sub-core-scale
‘capillary heterogeneity’
associated almost with all the cores,
towards estimating
either steady-state or transient relative permeability
@ laboratory-scale?
You pose a lot of general questions but need to clarify the issues; are you dealing with multi-phase flow through a simple permeable rock (as is common in reservoir engineering) or, as it appears, a generalised flow system? If the latter is the case, no single answer will exist.
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