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.
Beyond matrix porosity/permeability, economic shale gas exploitation depends on: (1) Total organic carbon (TOC) – higher TOC provides more adsorption sites and generally correlates with higher total gas-in-place. (2) Thermal maturity (vitrinite reflectance, Ro) – the shale must be in the gas window (typically Ro > 1.1–1.4%) to have generated dry gas rather than oil/condensate, and over-maturity can also degrade reservoir quality. (3) Gas content and its free/adsorbed split – total gas-in-place matters, but so does how much is free (immediately producible) vs. adsorbed (released more slowly as reservoir pressure declines, via the Langmuir isotherm), which controls the shape of the production decline. (4) Mineralogy and brittleness – a quartz/carbonate-rich, clay-poor shale fractures in a brittle, planar manner that props well and stays open, while a clay-rich shale deforms ductilely and tends to heal fractures shut, making it far harder to stimulate effectively. (5) Natural fracture density and orientation – pre-existing natural fractures can be reactivated by hydraulic stimulation to extend the effective drainage network, but can also short-circuit fracture growth toward unwanted zones (e.g. a nearby water-bearing interval). (6) In-situ stress regime and reservoir pressure – the minimum-to-maximum horizontal stress contrast controls induced fracture geometry (complexity vs. a single planar fracture), and higher initial reservoir pressure (pressure gradient above hydrostatic) generally improves both gas-in-place and deliverability. (7) Net thickness and depth – sufficient gross/net thickness is needed to justify the well cost per unit of contacted rock, while excessive depth raises both drilling/completion cost and closure stress (harder, more expensive fracturing) without a proportional increase in gas content.
