24-Pet-B2 Oil and Gas Evaluation and Economics · Undated paper
Nivaar worked solution (AI-drafted; not reviewed by a licensed engineer)
National Exams May 2019, 17-Pet-B2, Natural Gas Engineering — 3 hours, open book (non-communicating calculator permitted), 7 questions of equal (10-mark) value. NOTES item 5 states only the first five questions in the answer book are marked; all 7 are solved.
Reference texts: Katz et al., Handbook of Natural Gas Engineering; Lee & Wattenbarger, Gas Reservoir Engineering (SPE Textbook Series Vol. 5); Ahmed, Reservoir Engineering Handbook, 5th ed.; McCain, The Properties of Petroleum Fluids, 3rd ed.; Mohitpour et al., Pipeline Design and Construction, 3rd ed. (ASME Press); GPSA Engineering Data Book (component critical-property tables); Wichert & Aziz (1972), “Calculate Z's for Sour Gases,” Hydrocarbon Processing; Mandhane, Gregory & Aziz (1974), “A Flow Pattern Map for Gas-Liquid Flow in Horizontal Pipes,” Int. J. Multiphase Flow.
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.
(i) Gas reserve. The portion of the original gas in place (OGIP) that is technically and economically recoverable under defined operating and economic conditions, down to a stated abandonment point — a subset of OGIP, not the full volumetric figure computed in Question 7.
(ii) Effective permeability. The permeability of a porous medium to one fluid phase (e.g. gas) when two or more fluid phases are present simultaneously, measured at a given saturation of that phase; it is always less than or equal to the single-phase absolute permeability.
(iii) Relative permeability. The dimensionless ratio of a phase's effective permeability to the rock's absolute (single-phase) permeability, $k_{rj}=k_{eff,j}/k$; a saturation-dependent multiplier between 0 and 1 that corrects Darcy's law for multiphase flow.
(iv) Interfacial tension. The tensile force per unit length acting at the interface between two immiscible fluids (e.g. gas/water), arising from the imbalance of intermolecular attraction at the boundary; together with pore-throat radius it sets the magnitude of capillary pressure through the Young–Laplace relation.
(v) Resistivity index. $I_R=R_t/R_o$, the ratio of a partially water-saturated rock's true resistivity to that of the same rock fully (100%) saturated with formation water; the central quantity in Archie's water-saturation equation, $I_R=S_w^{-n}$.
(vi) Capillary pressure. The pressure difference across the curved interface between two immiscible fluids in a porous medium, $P_c=P_{nw}-P_w=2\sigma\cos\theta/r$, produced by interfacial tension acting across the pore-throat radius; it governs the fluid saturation distribution above a free-water level and, together with the wettability of part (viii), shapes the Q7-style reservoir's saturation profile.
(vii) Gas volume formation factor. $B_g=0.02827\,ZT/p$ (ft$^3$/SCF, $T$ in $^\circ$R, $p$ in psia) — the ratio of gas volume at reservoir (or line) conditions to its volume at standard conditions; used throughout this paper (Questions 3, 4, 7) to convert between flowing and standard gas volumes.
(viii) Wettability. The tendency of one fluid phase to preferentially adhere to and spread across the rock pore-wall surface in the presence of another immiscible phase, quantified by the contact angle $\theta$ measured through the denser (usually water) phase; it controls the sign and shape of the capillary-pressure curve of part (vi) and the shape of the relative-permeability curves of parts (ii)–(iii).
