Terminology and the Classification of Fine Grained
SEDIMENTARY ROCKS – is there a difference between a claystone, a mudstone and a shale? Summary Fine grained sedimentary rocks, both clastic and carbonate, are believed to be the most abundant rock type on the Earth " s surface 1924) of all the sediment ever produced. In sedimentology the size grade scale most commonly used is that which was introduced by Udden in 1898, modified by Wentworth in 1922 and then converted into a logarithmic form by Krumbien in 1934. For a single particle, the sand-silt boundary, which is the distinction between coarser grained materials and those which are fine grained, is placed at 1/16 mm (≈63 microns or +4 Φ). For a given rock the proportion of material containing particles less than 63 microns in size is normally greater than 50% to satisfy the classification criteria of being fine grained. Despite their abundance, fine-grained sedimentary rocks, to date, have not been satisfactorily classified. Perhaps this is because they are not well exposed in the field compared to their coarser grained, more weather resistant counterparts, the sandstones (Pettijohn, 1975; Spears, 1980); perhaps it is due to their fine grained nature that makes their study more noted by Rodgers (1950) the problem of classifying fine grained sedimentary rocks, simply, but inevitably entails the problem of terminology. It is the usage of imprecisely defined terms that has often led to confusion, and frustration, when trying to describe and discuss fine grained sediments. This report will identify where confusion has arisen, and determines the type of terminology and classification that will be used in future works. In the literature there is a plethora of names for fine grained sedimentary materials – Definition and usage of the word 'shale' The term shale has been around for a few centuries. The first recorded use of the written word shale appears in Hooson " s " The Miners Dictionary " , published in 1747; within which the term shale was meant as an indurated, laminated, clayey rock. Tourtelot (1960) gives a good summary on the origin and use of the world shale, and by outlining its historical use as i) a general term for describing " laminated clayey rock " ; ii) as a formation name, e.g. the " Pierre Shale " ; and iii) it " s widespread use as a bucket term for the entire class of fine grained rocks (whether they are laminated …
Core-scale heterogeneity and dual-permeability pore structure in the Barnett Shale
I present a stratigraphically layered dual-permeability model composed of thin, alternating, high (~9.2 x 10 -20 m 2 ) and low (~3.0 x 10 -22 m 2 ) permeability layers to explain pressure dissipation observed during pulse-decay permeability testing on an intact Barnett Shale core. I combine both layer parallel and layer perpendicular measurements to estimate layer permeability and layer porosity. Micro-computed x-ray tomography and scanning electron microscopy confirm the presence of alternating cm-scale layers of silty-claystone and organic-rich claystone. I interpret that the silty-claystone has a permeability of 9.2 x 10 -20 m 2 (92 NanoDarcies) and a porosity of 1.4% and that the organic-rich claystone has a permeability of 3.0 x 10 -22 m 2 (0.3 NanoDarcies) and a porosity of 14%. A layered architecture explains the horizontal (kH = 107 x 10 -21 m 2 ) to vertical (kV = 2.3 x 10 -21 m 2 ) permeability anisotropy ratio observed in the Barnett Shale. These core-scale results suggest that spacing between high-permeability carrier beds can influence resource recovery in shales at the reservoir-scale. I also illustrate the characteristic pulse-decay behavior of core samples with multiple mutually-orthogonal vii fracture planes, ranging from a single planar fracture to the Warren and Root (1963) “sugar cube” model with three mutually-orthogonal fracture sets. By relating sub corescale matrix heterogeneity to core-scale gas transport, this work is a step towards upscaling experimental permeability results to describe in-situ gas flow through matrix at the reservoir scale.
Predicting the gas resource potential in reservoir C-sand interval of Lower Goru Formation, Middle Indus Basin, Pakistan
Abstract The integrated study of seismic attributes and inversion analysis can provide a better understanding for predicting the hydrocarbon-bearing zones even in extreme heterogeneous reservoirs. This study aims to delineate and characterize the gas saturated zone within the reservoir (Cretaceous C-sand) interval of Sawan gas field, Middle Indus Basin, Pakistan. The hydrocarbon bearing zone is well identified through the seismic attribute analysis along a sand channel. The sparse-spike inversion analysis has efficiently captured the variations in reservoir parameter (P-impedance) for gas prospect. Inversion results indicated that the relatively lower P-impedance values are encountered along the predicted sand channel. To further characterize the reservoir, geostatistical techniques comprising multiattribute regression and probabilistic neural network (PNN) analysis are applied to predict the effective porosity of reservoir. Comparatively, the PNN analysis predicted the targeted property more efficiently and applied its estimations on entire seismic volume. Furthermore, the geostatistical estimations of PNN analysis significantly predicted the gas-bearing zones and confirmed the sand channel as a major contributor of gas accumulation in the area. These estimates are in appropriate agreement with each other, and the workflow adopted here can be applied to various South Asian regions and in other parts of the world for improved characterization of gas reservoirs.