24-Pet-B4 Well Testing · December 2015
Nivaar worked solution (AI-drafted; not reviewed by a licensed engineer)
EGBC National Exam — Petroleum Engineering, 2015-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, migration/unconventional reservoirs, carbonate traps, structural traps, Canadian basin geography) – 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. The paper is almost entirely qualitative (draw/describe/define/list), with one true numeric calculation (Q3-2, capillary seal-breach column height).
Reference texts: Selley, R.C. & Sonnenberg, S., Elements of Petroleum Geology, 3rd ed., Academic Press (source rocks, migration, traps, carbonate systems); 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 and carbonate lithofacies); Allen, P.A. & Allen, J.R., Basin Analysis: Principles and Applications to Petroleum Play Assessment, 3rd ed., Wiley-Blackwell (structural styles, unconventional systems); Biddle, K.T. & Wielchowsky, C.C., “Trap Types in Petroleum Basins,” AAPG Memoir 60, ch.12 (structural trap classification); James, N.P. & Jones, B., Origin of Carbonate Sedimentary Rocks, Wiley-Blackwell (carbonate platform/ramp/sabkha facies models); Law, B.E. & Curtis, J.B., “Introduction to unconventional petroleum systems,” AAPG Bulletin 86 (basin-centred gas); Mossop, G.D. & Shetsen, I. (eds.), Geological Atlas of the Western Canada Sedimentary Basin, CSPG/Alberta Research Council, 1994 (WCSB stratigraphy and Canadian basin geography).
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.
In a conventional gas reservoir, gas exists as a free, mobile phase in the pore space of a permeable reservoir rock at a pressure well above the gas's own critical desorption behaviour, so production is a straightforward pressure-depletion process: the well is opened, the pressure differential to the wellbore mobilizes the free gas directly, and production typically starts at or near its highest rate and then declines (following an Arps-type exponential/hyperbolic decline) as reservoir pressure falls.
In a coal-bed methane (CBM) reservoir, by contrast, the gas is not free in the pore space at all – it is adsorbed onto the internal micropore surface area of the coal matrix itself (described by a Langmuir isotherm, with coal able to hold far more gas per unit rock volume than an equivalent conventional pore-space reservoir would). This adsorbed gas is held in place by the hydrostatic pressure of water filling the coal's natural fracture network (the cleat system). Production therefore requires an initial dewatering phase: water is pumped from the cleats to reduce reservoir pressure, which allows gas to progressively desorb from the coal surface into the cleat system and then flow to the well. This gives CBM wells a characteristic production profile very different from conventional gas – water rate is highest and gas rate is near zero at first, then as dewatering proceeds gas rate ramps up (sometimes over months to a few years) to a peak before beginning a more conventional decline, rather than starting immediately at peak rate like a conventional well.
