24-Pet-A2 Petroleum Reservoir Fluids · December 2019
Nivaar worked solution (AI-drafted; not reviewed by a licensed engineer)
EGBC National Exam — Petroleum Engineering, 17-Pet-A2 Petroleum Reservoir Fluids, 2019-Dec. 3 hours duration, closed book (ruler and approved calculator only). SEVEN questions are printed on the paper; per the exam notes, FIVE questions constitute a complete exam paper and only the first five as answered are marked. Every question is solved in full below (all seven, not just the five a candidate would normally submit) so this set also serves as complete study material.
Reference texts: McCain, W.D., The Properties of Petroleum Fluids, 3rd ed. (PennWell); Ahmed, T., Reservoir Engineering Handbook, 5th ed.; Craft, B.C. & Hawkins, M.F., Applied Petroleum Reservoir Engineering, 3rd ed.; Standing, M.B., Volumetric and Phase Behavior of Oil Field Hydrocarbon Systems; Danesh, A., PVT and Phase Behaviour of Petroleum Reservoir Fluids.
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.
| # | Answer | Reasoning |
|---|---|---|
| i | True | Retrograde condensation occurs only for an isothermal pressure path at a temperature strictly between the mixture's critical temperature $T_c$ and its cricondentherm $T_{ct}$. If $T_c = T_{ct}$ there is no temperature window between them, so no isotherm can cross the two-phase envelope in the retrograde manner – retrograde condensation is impossible. |
| ii | False | n-Hexane boils at 68.7°C at 1 atm; 3-methylpentane, a branched isomer, boils lower at 63.3°C. Branching reduces intermolecular (van der Waals) contact area, which lowers the boiling point relative to the straight-chain isomer – so n-hexane's boiling point is higher, not lower. |
| iii | True | This is the operational definition of relative volatility: at a fixed pressure, the more volatile component has the higher vapour pressure and therefore reaches its vaporization point (boils) at a lower temperature. |
| iv | True | Raising temperature increases average molecular kinetic energy; the molecules move faster and spend less time within each other's attractive range, so the relative importance of intermolecular (cohesive) forces falls and the gas behaves more ideally – i.e. it becomes harder for the molecules to move together in a cohesive, liquid-like manner. |
| v | True | Above the bubble point the oil is undersaturated (single liquid phase, no free gas). Increasing pressure above $P_b$ simply compresses that liquid, so $B_o$ falls slightly as $P$ rises above $P_b$ – equivalently, $B_o$ at any $P>P_b$ is less than $B_{ob}$ at the bubble point, where dissolved gas content is at its maximum for the given liquid. |
| vi | True | Adding even a small mole fraction of propane/butane to methane shifts the hydrate stability curve toward much milder conditions – heavier hydrocarbons stabilize structure II hydrates, so a given hydrate risk is reached at a substantially lower pressure (at fixed temperature) than pure methane requires, i.e. a smaller degree of cooling/compression is needed to initiate hydrate formation. |
No. Numerically, Point D is just a pressure inside the two-phase envelope on each curve, but the physical process it represents is opposite for oils and for the retrograde gas. For the two oil curves (black oil, volatile oil), D lies below the bubble point: it marks a state where gas is evolving out of the liquid as pressure falls, and the plotted quantity is the shrinking liquid (oil) fraction remaining. For the retrograde gas, an equivalent point on its bell-shaped curve instead marks a state where liquid is condensing out of the gas as pressure falls (retrograde condensation) – the plotted liquid fraction is growing, not shrinking, and represents newly formed condensate, not a shrinking parent liquid. So although Point D sits at "the same visual location" on a liquid-vol-% vs pressure axis system, it does not correspond to the same underlying phase-behaviour mechanism across the three fluid types.
(d) Saturated vs undersaturated oil. A saturated oil is reservoir oil whose current pressure equals its bubble-point pressure $P_b$ – it holds the maximum amount of gas it can keep in solution at reservoir temperature, so any further pressure decrease immediately releases free gas. An undersaturated oil is reservoir oil whose current pressure exceeds $P_b$ – it could dissolve more gas than it currently holds, so pressure can decline all the way down to $P_b$ with no gas evolution, only liquid compression.
(e) Wet gas. A reservoir gas whose temperature exceeds the cricondentherm of its own phase envelope, so the fluid remains 100% single-phase gas throughout reservoir depletion (no liquid ever forms downhole). At the surface, however, cooling through the separator train crosses the phase envelope's dew-point line, so the gas does yield a liquid condensate at surface conditions – hence "wet" at surface, dry in the reservoir.
(f) Differential liberation test. A laboratory PVT test that reduces the pressure of an oil sample below its bubble point in a series of steps at reservoir temperature; at each step, all the gas that evolves is measured and then physically expelled from the cell before the pressure is dropped to the next step, so the remaining oil is always in contact only with the gas evolved at that particular step (never with gas evolved earlier). This simulates gas segregating and being produced separately from the oil in the reservoir (as it does, by gravity/differential permeability), in contrast to a flash (single-stage) liberation where all evolved gas stays in contact with the oil until the final pressure.
