Typical matrix permeability and porosity of economic shale gas plays: 24-Pet-B4 Well Testing, December 2016, Q12

Question 12 of 22: Typical matrix permeability and porosity of economic shale gas plays

Nivaar worked solution (AI-drafted; not reviewed by a licensed engineer)

Notes on this paper

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).

Section 4, Q4-2: Typical matrix permeability and porosity of economic shale gas plays (4 marks)

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.

Economically productive shale gas matrix permeability is extraordinarily low, typically on the order of 10–1,000 nanodarcies (≈0.00001–0.001 mD) – roughly four to six orders of magnitude below a typical conventional sandstone reservoir – which is precisely why gas can only be produced economically via horizontal wells and dense multistage hydraulic fracturing (creating flow paths on the order of metres rather than relying on the matrix to deliver gas over hundreds of metres). Matrix (total) porosity is comparatively modest, typically 4–12%, hosted in a combination of interparticle clay/silt porosity, organic-matter (kerogen) nanoporosity, and minor natural microfracture porosity – organic porosity in particular develops as kerogen thermally cracks and loses mass during gas generation, so it correlates with TOC and thermal maturity rather than with grain size or sorting as in a clastic reservoir.

Topic. Nanodarcy-scale matrix flow properties of economic shale gas reservoirs.

Key relations. Gas flow in shale matrix departs from simple Darcy flow at this pore-throat scale – Knudsen diffusion and gas slippage (Klinkenberg effect) both become significant, so apparent permeability to gas measured at low pore pressure can exceed the true liquid (Darcy) permeability.

Why this works. Porosity in shale is largely hosted within organic matter itself (organic nanopores generated as kerogen converts to hydrocarbon), so porosity and TOC/maturity are correlated rather than independent, unlike a clastic reservoir where porosity is a function of depositional sorting and burial compaction alone.

Common pitfall. Assuming a shale with 4–12% porosity should behave like a conventional reservoir of the same porosity – permeability, not porosity, is the binding constraint in shale gas, and the nanodarcy-scale matrix permeability (not the modest porosity) is what makes hydraulic fracturing mandatory.

Source. Law & Curtis, “Introduction to Unconventional Petroleum Systems”; Lee & Wattenbarger, ch.1.