A comprehensive regional investigation of the Eagle Ford Shale linking productivity to porosity-thickness (PHIH), lithology ([Formula: see text]), pore volume (PHIT), organic matter (TOC), and water-saturation ([Formula: see text]) variations has not been presented to date. Therefore, isopach maps across the Eagle Ford Shale play west of the San Marcos Arch were constructed using thickness and log-calculated attributes such as TOC, [Formula: see text], [Formula: see text], and porosity to identify sweet spots and spatial distribution of these geologic characteristics that influence productivity in shale plays. The Upper Cretaceous Eagle Ford Shale in South Texas is an organic-rich, calcareous mudrock deposited during a second-order transgression of global sea level on a carbonate-dominated shelf updip from the older Sligo and Edwards (Stuart City) reef margins. Lithology and organic-matter deposition were controlled by fluvial input from the Woodbine delta in the northeast, upwelling along the Cretaceous shelf edge, and volcanic and clastic input from distant Laramide events to the north and west. Local oxygen minimum events along the South Texas margin contributed to the preservation of this organic-rich source rock related to the Cenomanian/Turonian global organic anoxic event (OAE2). Paleogeographic and deep-seated tectonic elements controlled the variations of lithology, amount and distribution of organic matter, and facies that have a profound impact on production quality. Petrophysical modeling was conducted to calculate total organic carbon, water saturation, lithology, and porosity of the Eagle Ford Group. Thickness maps, as well as PHIH maps, show multiple sweet spots across the study area. Components of the database were used as variables in kriging, and multivariate statistical analyses evaluated the impact of these variables on productivity. For example, TOC and clay volume ([Formula: see text]) show an inverse relationship that is related to production. Mapping petrophysical parameters across a play serves as a tool to predict geologic drivers of productivity across the Eagle Ford taking the geologic heterogeneity into account.

The Haynesville shale gas play has significant potential, with an estimated original gas in place larger than that of the Barnett with roughly 63% of the Barnett's acreage. However, the drilling and completion costs of Haynesville are approximately three times as much compared with the Barnett. We present a production scenario for the Haynesville on the basis of wells existing by the end of 2012 and wells to be drilled over the next 3 decades and quantify uncertainties around it. The scenario is underpinned by geologic, engineering, and well-economics analyses, which reveal the important differences between the Haynesville and two other plays we analyzed previously, Barnett and Fayetteville. The production profiles are developed by use of data from 2,131 wells drilled between 2008 and 2011 in both Louisiana and Texas, and a transient-linear-flow model. We run sensitivity analyses on reasonable ranges for natural-gas price, remaining-developable acreage, improvements in technology and well-cost performance, and economic limit for shutting in a well. Our analysis indicates a cumulative production of roughly 46 Tcf in the base case, subject to many uncertainties. IntroductionThe Haynesville play is the third shale formation analyzed by our interdisciplinary team of geologists, petroleum engineers, and energy economists. Browning et al. (2013) and Gülen et al. (2014) reported the production outlooks for the Barnett and Fayetteville plays, respectively. As those studies indicated, shale plays are heterogeneous in geology within and across plays. The differences in geology can influence drilling and completions costs. The geography, topography, and proximity to natural-gas infrastructure and consumers also affect well economics and the pace of drilling activity. Differences in states' tax policies, local environmental policies, and permitting processes; existence of basic infrastructure, such as roads; and acceptance by local communities also play a role in modifying well costs and wellhead-netback pricing for revenue calculations.The geology of the Haynesville shale leads to wells with much-higher productivity than those in the Barnett and Fayetteville, but at a much-higher cost of drilling and completion because of the depth and high pressure of the formation. We divided the play into six productivity tiers. Because of the higher cost structure, drilling slowed down significantly in the play across all six tiers, from 970 completions in 2011 to 396 in 2012 when the natural-gas price averaged approximately USD 2.70/million Btu, the lowest price in real terms since the late 1990s. The breakeven price of an average well even in the best tier (Tier 1) is slightly more than the average Henry Hub gas prices of 2011 and 2012. As a result, many top-tier locations have been drilled only to the extent necessary to meet lease obligations. With the price recovering from that low level, the activity in 2013 and 2014 has been stabilized but still low (roughly 250 completions in 2013 and 160 for the first three quarters of 2013), b...

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