24-Pet-B2 Oil and Gas Evaluation and Economics · December 2014
Nivaar worked solution (AI-drafted; not reviewed by a licensed engineer)
National Exams December 2014, 98-Pet-B2, Natural Gas Engineering — 3 hours, closed book (Casio/Sharp approved calculators only), 7 questions of 20 marks each. 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.; Mohitpour et al., Pipeline Design and Construction, 3rd ed. (ASME Press); McCain, The Properties of Petroleum Fluids, 3rd ed.
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) Retrograde condensation. The formation of liquid from a single-phase gas as pressure is reduced isothermally below the upper dew-point curve, at temperatures between the critical temperature and the cricondentherm — the opposite of the everyday expectation that lowering pressure vaporizes more fluid.
(b) Dew point pressure. At a fixed temperature, the pressure at which the first infinitesimal drop of liquid appears from an initially single-phase gas as pressure is reduced; it defines the gas-side boundary of the two-phase envelope on a P-T diagram.
(c) Critical point. The temperature and pressure at which the intensive properties (density, composition) of the coexisting liquid and vapour phases become identical, so the two phases merge into one — the point where the bubble-point and dew-point curves meet.
(d) Circondentherm (cricondentherm). The maximum temperature at which two hydrocarbon phases can coexist in equilibrium; above it, the fluid is single-phase at any pressure.
(e) Wet gas. A reservoir fluid whose phase envelope lies entirely below reservoir temperature (single-phase gas in the reservoir at all pressures during depletion), but whose surface separator temperature/pressure path crosses into the two-phase region, yielding a small liquid condensate volume at the surface — no retrograde liquid ever forms in the reservoir itself.
(f) Pseudopressure. The real-gas potential $m(p)=2\int_{p_0}^{p}\dfrac{p}{\mu(p)Z(p)}\,dp$, a transform that absorbs the pressure dependence of viscosity and $Z$-factor so the real-gas diffusivity equation can be solved with the same analytical machinery as liquid flow, valid across the full pressure range (not just where $\mu Z\approx$ constant).
(g) Absolute open flow (AOF). The theoretical maximum rate a well could deliver if produced against a sandface pressure of atmospheric (0 psig); used as a standardized capacity metric to compare wells even though a well is never actually produced at that condition.
(h) Accuracy of a flow meter. How close the meter’s indicated value is to the true value of the quantity measured — a measure of systematic bias.
(i) Liquid drop out. The volume percentage of retrograde liquid that condenses from a gas-condensate system (relative to the original hydrocarbon pore volume) as pressure falls below the dew point, measured via a constant-composition-expansion (CCE) test and reported as a liquid-dropout curve vs. pressure.
(j) Repeatability (precision) of a flow meter. The closeness of agreement among repeated measurements of the same quantity under the same conditions — a measure of random scatter, independent of whether the average of those readings is close to the true value (accuracy).
