Abstract Observations by transmission and scanning electron microscopy (TEM and SEM) of surficial sediment microfabric along with quantitative geochemical tests of organic matter from continental margin deposits reveal important fundamental interrelationships of material properties and processes during diagenesis of mud to shale. Fine-grained surficial muds possessing ≥2% total organic carbon (TOC) and ≥5% smectite commonly have very high porosities (≥90%), low wet bulk densities, and very low effective stresses that are consistent with minimal dewatering and consolidation in the upper few meters subbottom. These muds are characterized by random orientation of clay domains and marine organic material in the form of mucopolysaccharides and living microbiota that bridge between clay particles and aggregates and commonly appear to fill pore space in 2-D EM views. These fine-grained, organic-smectite-rich, clayey muds consolidate to very low porosities (≤30%) under relatively low overburden stress (∼1000 kPa or ∼120 m below the seafloor). In contrast, similar smectite-rich clayey muds possessing ∼0.5% TOC consolidate to approximately the same porosities but at loads of at least six times the overburden stress. In both cases, the microfabric observed by TEM and SEM following consolidation reveals a strong preferred clay particle orientation normal to the direction of the effective stress indicative of significant anisotropy in the permeability. Sandy clayey silts (62%-75% silt) that possess TOC contents of 1.3% to 4.2% consolidate remarkably different from the organic-rich clayey muds. The sandy clayey silts display porosities well above 38% at high consolidation stresses and show significant resistance to consolidation at high stresses probably due to grain-to-grain contact of the sand and large silt particles. Despite the exceptionally high depositional porosities of the sandy clayey silts, these muds, even those having high TOC, dewater significantly less under large consolidation stress compared to the organic-smectite-rich clayey sediments. A general correlation is found in the fine-grained sediment between the amount of smectite and the amount of organic material in the sediment. Studies have shown that smectite has a strong affinity for organic material and correlates well with water content, high porosities, and low wet bulk densities. Thus, the presence of organic material (≥2% TOC) largely controls the microfabric during early sediment diagenesis and has a significant impact on post depositional consolidation. The microfabric, mineralogy, and organic content of muds largely control the porosity and permeability of not only the sedimentary analogs of mudstone and shale but also largely determines the ultimate properties of the rocks in the geologic column. Noteworthy is that many highly fissile shales are rich in organic material. It is postulated that the presence of large amounts of organic material ( i.e ., ≥2% TOC) in sediments during consolidation and early diagenesis may ultimately affect the mechanical properties and response of the mudstones and shales during deep burial and tectonic stresses at passive and active margins and in epicontinental seas. The insoluble organic component of sedimentary rocks, kerogen, can be differentiated on the basis of the amount of hydrogen and carbon present in the material. The different types of kerogen influence not only the consolidation behavior but also may affect the development of fractures and migration pathways during continental margin evolution. Upon thermal maturation, some geochemical types of kerogen produce oil (types I and II), while type III produces natural gas. Kerogen of mainly terrestrial origin (type III) consists largely of negatively-charged polymers that inhibit adsorption of the organic matter onto negatively-charged clay mineral surfaces. Type I and II kerogen, which are of marine origin, are more readily adsorbed onto clay particles and can be expected to influence the development of geotechnical properties differently than kerogen of terrestrial origin. The kerogen types would be expected to behave differently in different stratigraphic sequences and perhaps even enhance fracture healing, retard stress fracturing, or conversely, promote fracturing during deformation. Thus, the clay microfabric, organic content, and isotropy/anisotropy of a mudrock or shale largely determines the stratigraphic formation functionally in terms of its role as either a petroleum source rock, reservoir seal, or migration pathway. Continental margin tectonic patterns result from regional stress fields imposed on stratigraphic sequences developed with different properties characteristic of the environments of deposition. The rock types developed and the productivity of the source rocks at depth appear to primarily depend upon the mineralogy, grain size distribution, organic material, microfabric, stress regime/depth of burial, and probably the differences in the material properties (porosity, permeability, strength, etc. ) of the sand, mudstone, and shale in the stratigraphic sequences.

ABSTRACT The Devonian-Mississippian Chattanooga (Woodford) Shale and equivalent formations are widely distributed in North America. Deposited under generally anoxic conditions during the Kaskaskian marine transgression, they are known to be important petroleum source rocks in many intracratonic basins of the Midcontinent. The formation can be divided into several members, including the basal Misener Sandstone, and informally designated lower, middle, and upper shale members. The middle shale member is the most radioactive part of the formation, although the radioactivity of all three members decreases to the north. Isopach maps of the shale members in northwestern Oklahoma and Kansas show that the middle shale member has the greatest areal extent and thickness, indicating that it was deposited when the Kaskaskia I transgression was at its maximum. Total organic carbon content of the three shale members decreases to the north, but the middle shale member is the most organic-rich part of the formation and has the greatest component of hydrogen-rich type I and II organic matter, making it the part of the Chattanooga (Woodford) Shale likely to be the best petroleum source rock where the formation is thermally mature. The shale members of the Chattanooga (Woodford) Shale represent a third-order depositional sequence that is bounded below and above by unconformities. The distribution and organic geochemistry of the shale members suggest that the lower, middle, and upper shale members are the transgressive and early and late highstand systems tracts of the sequence.