24-Pet-B2 Oil and Gas Evaluation and Economics · May 2015
Nivaar worked solution (AI-drafted; not reviewed by a licensed engineer)
National Exams May 2015, 98-Pet-B2, Natural Gas Engineering — 3 hours, closed book (non-communicating calculator permitted), 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) Dry gas. A reservoir hydrocarbon system that remains entirely single-phase gas throughout the reservoir depletion path and at surface separator conditions — it is almost pure methane/ethane and yields no liquid condensate at any point in the production process.
(b) Cricondenbar. The maximum pressure at which two hydrocarbon phases (liquid and vapour) can coexist in equilibrium; above it, the fluid is single-phase at any temperature — the phase-envelope counterpart of the cricondentherm (which is the maximum temperature).
(c) Water content. The mass (or volume) of water vapour carried per unit volume of natural gas at a given pressure and temperature (typically lb$_m$/MMSCF), used to size dehydration facilities and check against the hydrate/corrosion dew point in a pipeline.
(d) Volumetric gas reservoir. A gas reservoir with no significant aquifer support, so reservoir pressure declines essentially in proportion to cumulative gas withdrawn (constant hydrocarbon pore volume) — the condition that makes the linear $p/Z$ vs. $G_p$ material-balance straight line valid.
(e) Pigging operation. Passing a cylindrical or spherical “pig” through a pipeline (driven by the flowing fluid) to remove liquids, wax, scale or debris and restore flow capacity, or to inspect/gauge the line internally.
(f) Gas formation volume factor. $B_g=0.02827\,ZT/p$ (ft$^3$/SCF) — the ratio of gas volume at reservoir conditions to its volume at standard conditions, used to convert reservoir-condition gas volumes into surface (sales) volumes and vice versa.
(g) Well deliverability. The relationship between a gas well’s flowing bottomhole pressure and its production rate (the $q=C(\bar p^2-p_{wf}^2)^n$ or $q=C'(\bar p^2-p_{wf}^2-Bq)$ back-pressure/LIT curve), used to predict the rate a well can sustain against any specified surface or bottomhole constraint.
(h) Acid gas. A gas stream (or the CO2+H2S fraction stripped from natural gas by amine treating) that is acidic in the presence of water, forming carbonic/sulfurous acid that corrodes carbon-steel equipment — the term specifically denotes the concentrated CO2/H2S stream sent to sulfur recovery or acid-gas injection.
(i) Sour gas. Natural gas containing H2S above a regulatory threshold (in Canada, per CSA Z662/AER, generally $\ge 10$ ppm in the gas phase, with the H2S release rate additionally classifying the well under AER Directive 056) — it requires sour-service metallurgy and H2S safety planning, unlike sweet gas.
(j) Orifice meter. A differential-pressure flow meter that infers gas rate from the pressure drop across a thin plate with a precisely-sized circular bore installed in the pipeline (per AGA-3/ISO 5167), widely used for natural-gas custody transfer because it has no moving parts and is well characterized empirically.
