24-Pet-B4 Well Testing · December 2016
Nivaar worked solution (AI-drafted; not reviewed by a licensed engineer)
EGBC National Exam — Petroleum Engineering, 2016-Dec. 3 hours duration; closed book. This sitting's own cover page reads “98-Pet-B4, Petroleum Geology” and every question is descriptive/interpretive petroleum geology (source rocks, hydrocarbon chemistry, oil sands and tight-oil development, shale gas and coalbed methane, carbonate traps, siliciclastic/deltaic traps) – no well-test pressure-transient content anywhere. Five (5) of the paper's six 20-mark sections are marked (NOTES item 5); all six are solved in full below so this set also serves as a complete study reference. This sitting's Section 6 is a Siliciclastic Traps section (wave-dominated delta, grain-size–permeability–porosity relations, sandstone diagenesis). The paper is entirely qualitative (draw/describe/define/list), with no numeric given data anywhere.
Reference texts: Selley, R.C. & Sonnenberg, S., Elements of Petroleum Geology, 3rd ed., Academic Press (source rocks, migration, traps, carbonate systems, oil sands); Tissot, B.P. & Welte, D.H., Petroleum Formation and Occurrence, 2nd ed., Springer (kerogen typing, maceral groups, catagenesis); Boggs, S. Jr., Petrology of Sedimentary Rocks, 2nd ed., Cambridge (source-rock, deltaic and carbonate lithofacies; sandstone diagenesis); James, N.P. & Jones, B., Origin of Carbonate Sedimentary Rocks, Wiley-Blackwell (carbonate platform/ramp/sabkha facies models); Butler, R.M., Thermal Recovery of Oil and Gas, Prentice Hall, 1991 (SAGD, CSS, oil sands thermal recovery); Green, D.W. & Willhite, G.P., Enhanced Oil Recovery, SPE Textbook Series Vol. 6 (thermal EOR mechanisms); Law, B.E. & Curtis, J.B., “Introduction to Unconventional Petroleum Systems,” AAPG Bulletin 86, 2002 (shale gas, tight gas, coalbed methane); Lee, W.J. & Wattenbarger, R.A., Gas Reservoir Engineering, SPE Textbook Vol. 5 (unconventional gas reservoir characterization).
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.
| Fluid | Typical API gravity | Typical reservoir viscosity |
|---|---|---|
| (a) Heavy oil | 10–22° API | ≈100–10,000 cP |
| (b) Light oil | 31–40+° API | ≈0.5–10 cP |
| (c) Bitumen | <10° API | >10,000 cP (commonly >1,000,000 cP; essentially immobile without thermal or diluent stimulation) |
| (d) Water (fresh/formation) | ≈10° API (SG≈1.0, the API-scale reference point) | ≈0.3–1 cP at typical reservoir temperature |
API gravity and viscosity both track the same underlying property – the proportion of large, heavy, aromatic/asphaltenic molecules versus small, light paraffinic ones – but in opposite senses: as API gravity falls (denser fluid), viscosity rises, non-linearly and often by several orders of magnitude. Light oil is dominated by low-molecular-weight paraffins and flows almost like a light lubricating oil; heavy oil and bitumen are progressively enriched in asphaltenes and resins, which raise both density and viscosity dramatically – bitumen at typical Western Canadian reservoir temperature (≈10–15 °C) is for practical purposes a solid or semi-solid and will not flow to a well under primary depletion at all, which is precisely why thermal recovery (Q3-3) is required. Water is included as the API-scale reference fluid (API 10° ≡ SG 1.0) and, being a low-viscosity Newtonian fluid at reservoir temperature, provides the baseline against which oil mobility ratios in a waterflood or steamflood are judged.
