Abstract The Upper Kimmeridgian to Lower Tithonian Haynesville Shale of East Texas was deposited in a basin rimmed by carbonate platforms to the west and north during a second-order transgression spanning 154–150 Ma. The Haynesville shale gas play is an important resource target in Louisiana and East Texas. Wells are characterized by high initial production and steep decline rates. Potential estimated ultimate recovery (EUR) per well is in the range of 4–7 Bcf, and playreserves of more than 100 Tcf. However, depositional environmental, mineralogy, lithology, textures, geochemistry, porosity, permeability, and wireline-log characteristics are all poorly documented or understood. This paper addresses previously undocumented parameters related to depositional setting, facies, diagenesis, pore space, petrophysics, and significant geochemical markers of the Haynesville Shale. The Haynesville Shale was deposited in a basinal setting surrounded by carbonate shelf of the Haynesville/Cotton Valley Lime. Cotton Valley pinnacle reefs grew within the shale-rich basin. Deposition was during a rapid second-order transgression that resulted in back-stepping of carbonates and smothering of carbonate production by the Haynesville fine-grained sediments. Carbonates were shed into the basin via gravity flows. The basin periodically exhibited a restricted environment of reducing anoxic conditions, as indicated by Molybdenum (Mo) and Fe/S concentrations. Relatively high TOC values (1–8%) are typical of these mudrocks that ranged from calcareous, laminated and/or biotur-bated mudstones to unlaminated siliceous mudstones. Bioturbation may be indicative for smaller-scale sea-level fluctuations and/or anoxic/oxic cycles. Pores are limited and small in size, occurring as micropores and nannopores in both intraparticle and interparticle forms. Nanopores are common and well-developed in some organic matter. Kerogen is seen to affect responses of all logs used for petrophysical characterization of porosity and lithology. Therefore, corrections must be applied when calculating porosity and clay volume.

Abstract Fracture geometries and fracture-sealing characteristics in dolostones reflect interactions among mechanical and chemical processes integrated over geological timescales. The mechanics of subcritical fracture growth results in fracture sets having power-law size distributions where the attributes of large, open fractures that affect reservoir flow behaviour can be accurately inferred from observations of cement-sealed microfractures and other microscopic diagenetic features, which are widespread in dolostones. Fracture porosity is governed by the competing rates of fracture opening and cement precipitation during fracture growth and by cements that post-date fracture opening. Combined analysis of structural and diagenetic features provides the best approach for understanding how fracture systems influence fluid flow. We review previous work and integrate new data on fractures and diagenetic features in cores from the Lower Ordovician Ellenburger and Permian Clear Fork formations in West Texas, and the Lower Ordovician Knox Group in Mississippi, together with outcrop samples of Lower Cretaceous Cupido Formation dolostones from the Sierra Madre Oriental, Mexico, in order to illustrate our approach.