Porosity and Pore Systems in Gas Shales: Posidonia and Wealden
Mathia, Eliza; Rexer, Thomas; Aplin, Andrew; Bowen, Leon
Free gas in shales occurs mainly in larger mesopores (width >3 nm) and macropores (width >50 nm) and is likely to be the first or even main contributor to gas production. Quantifying the amount, size distribution and connectivity of these pores is thus at the heart of both storage and production issues. Here, the pore systems of shale from the Lower Jurassic Posidonia and Lower Cretaceous Wealden formations, covering a range of lithologies and maturities, have been characterised using mercury injection (pore radii >3 nm), Focused Ion Beam (FIB) (>2 nm) and Broad Ion Beam (BIB) (>4 nm) microscopy. Key aims were to quantify the evolution of meso and macroporosity associated with both organic matter and inorganic rock matrix.
In both cases, total porosity is ca.10% at maturities of 0.6% Ro, declining to ca.4% at Ro = 0.9% as a result of compaction, pore-filling bitumen and perhaps kerogen swelling. At Ro = 1.4 - 1.6%, porosities increase to values similar to those at 0.6% Ro, related to gas and oil generation and perhaps organic matter contraction. "Image" porosity (>4-200 nm depending on magnification) accounts for 10-40% of total porosities and is mainly within the macropore size range. Almost all image porosity in immature and oil window samples is associated with the inorganic matrix, with some evidence for porosity development at the interface of organic and inorganic matter in the oil window. In contrast, within the gas window, 20% of imaged porosity is associated with the organic phase. Importantly, neoformed organic porosity is highly heterogeneous; 60% of organic particles contain visible porosity, with porosities of individual particles ranging from 0-50%. Lithology also influences image porosity, with twice the amount in calcareous-fossil bearing Posidonia shale compared to clay-rich Wealden at equivalent maturities (1.5% Ro). This relates to the occurrence of fossiliferous zones which appear to be preferential sites for bitumen retention and degradation; these zones have image porosities up to 7% compared to 9-12% for the bulk samples.
Combined mercury injection and SEM data show that visible but potentially isolated macropores are connected, but only through throats below 20 nm, the size of which depends on maturity, mineralogy and texture of the bulk rock. The size of these pore throats, and the connectivity of the organic system in the shales, are likely key controls on the delivery of gas from pore to fracture and then to wellbore.
AAPG Search and Discovery Article #90163©2013AAPG 2013 Annual Convention and Exhibition, Pittsburgh, Pennsylvania, May 19-22, 2013