Question 3 of 6: Section 3: Migration

Section 3: Migration (20 Marks)

Question text not reproduced: the examination questions are © Engineers and Geoscientists BC. Open the official past paper (linked at the top of this page) to read the question, then follow the worked solution below.

Q3-1 — Primary vs. secondary migration. Primary migration is the expulsion of newly generated hydrocarbons out of the fine-grained, low-permeability source rock and into an adjacent, more permeable carrier bed (driven by compaction, generation-overpressure micro-fracturing, or continuous oil-phase flow). Secondary migration is the subsequent movement of that hydrocarbon, now as a discrete phase, through the permeable carrier bed/reservoir toward a trap — driven predominantly by buoyancy (the density contrast between hydrocarbon and formation water), assisted by hydrodynamic flow of the formation water itself.

Q3-2 — Effective porosity and its relation to permeability. Effective porosity is the fraction of bulk rock volume occupied by interconnected pore space accessible to fluid flow, as opposed to total porosity, which also counts isolated, dead-end pores that trap fluid but cannot transmit it. Because permeability measures a rock's ability to transmit fluid through connected pathways, it correlates with effective porosity, not total porosity — a rock can have high total porosity (e.g. vuggy carbonate with abundant isolated moldic pores) yet near-zero permeability if those pores are not connected. Even among rocks of similar effective porosity, permeability further depends on pore-throat size, sorting and tortuosity (Kozeny-Carman-type relationships), so effective porosity is a necessary but not sufficient predictor of permeability.

Q3-3(A) — The Young-Laplace equation for hydrocarbon displacement pressure.

Given. A water-wet pore throat of radius $r$ that hydrocarbon must enter by displacing the wetting water phase.

Find. The Young-Laplace (capillary displacement pressure) equation and its variables.

1. Young-Laplace equation. $$P_c = \frac{2\,\sigma\cos\theta}{r}$$ where $P_c$ = capillary (displacement) pressure — the minimum pressure difference between the non-wetting hydrocarbon phase and the wetting water phase needed for hydrocarbon to enter and displace water from the pore throat; $\sigma$ = interfacial tension between the hydrocarbon and water phases; $\theta$ = wetting (contact) angle measured through the water phase at the hydrocarbon-water-rock contact line ($\theta\approx0$ for a strongly water-wet system, so $\cos\theta\approx1$); $r$ = radius of the pore throat (the constriction between pores, not the pore body itself).

Q3-3(B) — Effect of shrinking pore throats. Because $P_c \propto 1/r$, a decrease in pore-throat radius increases the displacement pressure required for hydrocarbon to enter that throat. Since the buoyancy pressure available to drive hydrocarbon migration is itself proportional to the height of the connected hydrocarbon column below the point of interest, $P_{buoy}=(\rho_w-\rho_{hc})\,g\,h$, a higher required $P_c$ means a taller hydrocarbon column must accumulate beneath a seal (or below any given depth in a reservoir) before enough buoyancy pressure builds up to force hydrocarbon through the smaller throats. This is exactly why fine-grained seals (shale, evaporite) with very small pore throats can support tall hydrocarbon columns before leaking, while a coarse, well-sorted carrier bed with large pore throats offers little resistance and cannot trap hydrocarbon on its own.

Q3-4 — Irreducible water saturation. Irreducible (connate) water saturation, $S_{wi}$, is the water saturation remaining in the reservoir after hydrocarbon has migrated in and displaced water down to the point where capillary and adsorptive forces hold the remaining water so tightly (in the smallest pore throats and as a thin wetting film on grain surfaces) that no additional buoyancy pressure, however large, can displace it further — a physical floor on water saturation, not a producible quantity. In a water-wet, medium-grained, well-sorted sandstone reservoir, pore throats are relatively large and uniform, so capillary retention is comparatively low; a typical value is $S_{wi}\approx15\text{-}25\%$ (versus >40-50% in a poorly-sorted or fine-grained/silty sandstone, where much smaller pore throats hold far more irreducible water).

Q3-5 — Pressure-depth profile, normally pressured region.

In a normally pressured region, pore pressure follows the hydrostatic gradient (≈10.2 kPa/m for typical formation water, SG≈1.04) because the pore-fluid column is in open, connected communication all the way to a free surface outlet. The lithostatic (overburden) gradient (≈22.6 kPa/m, using an average rock+fluid bulk density of ≈2.3 g/cm³) is much steeper because it is carried by the full weight of overlying rock, not just the pore fluid. An impermeable boundary such as a shale bed is identified on the plot where the measured pressure trend breaks away from the hydrostatic line and steps toward (though rarely all the way to) the lithostatic line: below the seal, compaction-expelled pore fluid cannot escape upward, so it partially supports the overburden load itself and pressure rises faster than hydrostatic — this abrupt gradient change (rather than a smooth continuation of the hydrostatic trend) is the diagnostic signature of a top-seal/pressure-compartment boundary on a pressure-depth plot.

Q3-6 — Best seal rock types. Evaporites (rock salt, anhydrite/gypsum) make the best seals: they have essentially zero primary permeability, deform ductilely (flowing rather than fracturing under stress, so they self-heal rather than developing through-going fracture leak paths), and are laterally very continuous. Shale/mudstone is the next-best and by far the most common seal in practice — fine grain size gives very small pore throats and correspondingly high displacement pressure, though shale is more prone to brittle fracturing and fault-related leakage than salt. In general, a good seal combines very low permeability (small, poorly connected pore throats), ductile rather than brittle mechanical behaviour, and lateral continuity across the whole trap.

Q3-7 — A fault as both pathway and seal. A fault's sealing behaviour depends on what it juxtaposes and on the state of clay/gouge material within the fault zone, both of which can differ along the fault or through time. It acts as a transport pathway where it juxtaposes permeable reservoir against permeable reservoir across the fault plane (so the fault surface itself offers no resistance), or where the fault plane is dilatant/open — commonly true immediately after active slip, before diagenetic sealing has occurred. The same fault surface acts as a seal where displacement instead juxtaposes reservoir against a low-permeability unit (shale-on-sand juxtaposition seal), or where enough clay-rich material has been smeared into the fault zone during slip (a high Shale Gouge Ratio) to form a low-permeability gouge that blocks across-fault flow even where reservoir is juxtaposed against reservoir. Because juxtaposition and gouge content both vary along strike/dip and can change through subsequent diagenesis or reactivation, one segment (or one point in geologic time) of a single fault surface can leak while another segment (or a later, cemented/gouge-filled state of the same surface) seals.