24-Pet-A3 Fundamental Reservoir Engineering · May 2014
Nivaar worked solution (AI-drafted; not reviewed by a licensed engineer)
98-Pet-A3 — Fundamental Reservoir Engineering · National Exams, May 2014 · 3 hours, closed book, non-communicating calculator only · first five questions in the answer book are marked, all questions equal value, all parts of a multipart question equal weight. All seven questions are answered here as a complete study resource.
Reference texts: Craft, B.C. & Hawkins, M.F., Applied Petroleum Reservoir Engineering, 3rd ed. (material balance, transient well testing, radial flow); Ahmed, T., Reservoir Engineering Handbook, 5th ed. (material balance, skin/productivity, relative permeability); McCain, W.D., The Properties of Petroleum Fluids, 3rd ed. (PVT properties, Z-factor); Lyons, W.C. (ed.), Standard Handbook of Petroleum and Natural Gas Engineering, 3rd ed. (core analysis, capillary pressure).
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.
a) Critical gas saturation ($S_{gc}$). The minimum gas saturation at which the gas phase first becomes continuous through the pore network and begins to flow under an applied pressure gradient. Below $S_{gc}$, liberated gas exists only as isolated, disconnected bubbles held in place by capillary forces and contributes nothing to gas relative permeability.
b) Dry gas reservoir. A reservoir whose fluid composition and phase envelope are such that neither the reservoir depletion path (constant temperature) nor the surface separator path ever crosses into the two-phase region. No liquid condenses anywhere in the production process, so the produced stream is essentially all gas with negligible stock-tank liquid yield.
c) Solution gas drive. The primary recovery mechanism, once reservoir pressure falls to or below the bubble point, in which gas liberated from solution in the oil expands and provides the principal driving energy pushing oil toward the wellbore. In the absence of water influx or a gas cap it is usually the dominant (and least efficient) natural drive mechanism.
d) Secondary gas cap. A free-gas accumulation that forms during depletion of a reservoir that was initially undersaturated or exactly at the bubble point — as pressure drops below $p_b$, gas evolves from solution and, being buoyant, migrates updip to collect at the structural crest, distinct from a primary gas cap already present at discovery.
e) Residual oil saturation ($S_{or}$). The oil saturation left behind, trapped and immobile in individual pores, after a displacing fluid (water or gas) has swept through a given rock volume as completely as that displacement mechanism can achieve. It represents oil unrecoverable by that mechanism alone and is the target of enhanced-recovery methods.
f) Overburden pressure. The total vertical stress at a given depth caused by the weight of the overlying rock-plus-fluid column above it. By the effective-stress principle it is shared between the rock's own grain-to-grain contact stress and the pore-fluid pressure, so overburden pressure is not the same quantity as reservoir (pore) pressure.
g) Gas compressibility factor (Z). The dimensionless correction in the real-gas law $pV=ZnRT$ that accounts for the deviation of a real reservoir gas from ideal behaviour at reservoir pressure and temperature. Z is obtained from pseudo-reduced properties (Standing–Katz correlation) and is essential for converting gas volumes between reservoir and standard conditions.
h) Interfacial tension (IFT). The energy per unit area (equivalently, force per unit length) that exists at the boundary between two immiscible fluid phases, such as oil–water or oil–gas, arising from the imbalance of intermolecular attraction at the interface. IFT is the physical origin of capillary pressure and governs how readily one phase displaces another through a pore throat.
i) Productivity index (PI). A measure of well deliverability, $J=q/(\bar p-p_{wf})$, the flow rate produced per unit pressure drawdown between average reservoir pressure and flowing bottom-hole pressure. It compresses reservoir quality, thickness, and near-wellbore condition (skin) into a single number used to forecast and compare well performance.
j) Drainage process. In capillary-pressure/relative-permeability terms, drainage is the displacement in which the non-wetting phase invades and displaces the wetting phase (e.g. oil or gas entering a water-saturated rock), increasing non-wetting-phase saturation. It is the opposite of imbibition, generally requires progressively higher capillary pressure to advance, and is the process by which the original hydrocarbon accumulation was emplaced.
