ABSTRACT Upper Triassic and Lower to Middle Jurassic strata in the Plomosas uplift of central Chihuahua accumulated in backarc and rift settings, respectively. The succession, as much as ~3250 m thick, consists of four stratigraphic units. The Cerro El Carrizalillo Formation (Carnian–Norian), a volcanic-lithic shallow-marine succession deposited in the (newly named) El Carrizalillo backarc basin, is characterized by predominantly Triassic detrital zircon ages. The overlying Plomosas Formation consists of three members: (1) the Cerro de Enmedio Member (Hettangian–Toarcian), a succession of conglomerate, siltstone, and shallow-marine carbonate strata deposited during the onset of extension in Chihuahua; (2) the Cerro Nevado Ignimbrite Member (176 ± 1 Ma; late Toarcian), a widespread ash-flow tuff; and (3) La Sofía Member (Aalenian–Callovian?), consisting of alluvial-fan conglomerate, fluvial sandstone, tidal sandstone and siltstone, and delta-plain red beds characterized by rapid facies changes, lithic compositions, and diverse Proterozoic, Paleozoic, and Triassic detrital zircon ages characteristic of a rift-basin setting. The extensional basin in which the Cerro de Enmedio and La Sofía members accumulated is termed the Plomosas basin. Improved age control provided by U-Pb maximum depositional ages from detrital zircon and U-Pb zircon analyses of the ignimbrite indicates that the Cerro El Carrizalillo Formation is partly correlative with the Chinle Formation of the Colorado Plateau, and the Plomosas Formation is equivalent to eolianites of the Glen Canyon and San Rafael Groups of the Colorado Plateau. Detrital zircon ages and sandstone textures are consistent with both proximal and distal sediment sources along the Laurentia-Gondwana suture and adjoining Grenville basement of Laurentia, including sources in northern Mexico and the composite Appalachian orogen. Although the depositional setting of the Cerro El Carrizalillo Formation was not connected to fluvial systems of the Chinle Formation, subsequent eolian transport of voluminous sediment to the overlying Cerro de Enmedio and La Sofía members from the Colorado Plateau ergs is suggested by the composition and texture of some sandstone, thick siltstone accumulations, and detrital zircon characteristics that broadly resemble those of the Colorado Plateau eolianites. Thick siltstone in the upper part of La Sofía Member is interpreted as deflated fine-grained sediment that was transported downwind from a time-equivalent erg to accumulate in shallow-marine and coastal-plain settings of the Plomosas basin.

Abstract Scanning electron microscopy (SEM) has become a common way to estimate porosity and organic matter (OM) content within shale resource rocks. Since quantitative SEM analysis has emerged as a means for assessing the porosity of shale, a common goal has been to image polished samples at the highest possible resolutions. Because nanopores are visible at pixel resolutions ranging from 5 to 10 nm, it is natural to consider the possibility of a pore regime below 5 nm that could contribute a significant amount to the total porosity of the system. When considering that a molecule of methane gas is on the order of 0.4 nm diameter, pores smaller than 5 nm could contribute significant storage volume and transport pathways in a reservoir. These nanopores may be a significant source of porosity within certain OM bodies, where total detectable pores using SEM (i.e., ~10 nm pore body diameter and up) have been observed to be volumetrically equivalent to the OM body volumes themselves. With the potential to examine the population of pores below ~10 nm in diameter using the helium ion microscope (HIM), it is possible to construct a rock model that is more representative of the varied pore size regimes present. The primary goal of this study was to quantify the amount of organic-associated pores below the resolution of conventional field emission scanning electron microscope (FESEM). In this study, 51 individual imaging locations from 12 organic shale samples were selected for systematic imaging using a HIM. These samples and locations were selected because of the presence of porous OM identified from previously completed SEM imaging. After methodical HIM imaging and digital segmentation, it was concluded that most samples had no significant incremental, resolvable, organic pore fraction below the detection threshold of conventional FESEM imaging. The advanced resolution of the helium ion beam provides sharper definition of pore boundaries, but the total porosity fraction of these <10 nm diameter pores within the OM in most samples was negligible. We also notice that FESEM and HIM can be considered complementary techniques, as each provides beneficial information that cannot be obtained from using only one method.

Abstract The subsurface Upper Jurassic Haynesville and Bossier Formations comprise three facies associations along the eastern slope of the Gilmer Platform. The lower Haynesville facies association consists of three facies produced by mass-wasting processes: (1) calcirudite/calcarenite, (2) mud-clast calcarenite, and (3) laminated calcisiltite intercalated with laminated calcareous mudrock and bioturbated calcareous mudrock. These facies were deposited by (1) hyperconcentrated density flows/transitional concentrated density flows, (2) hydrated turbidity flows, and (3) distal settling from turbidity flows, respectively. These mass-wasting deposits are the deeper water equivalents of the shallower water Haynesville Lime. The sedimentary dynamics of the mass-wasting processes produced TOC (total organic content)-rich accumulations downslope in the deeper parts of the basin. The upper Haynesville facies association also consists of three facies: (1) TOC-rich laminated calcareous mudrock, (2) bioturbated calcareous mudrock, and (3) bioturbated mud-clast calcisiltite. These facies were derived from marine snow deposited and reworked as sediment drifts by bottom currents above and below the oxycline. The Bossier Formation facies association contains (1) massive argillaceous mudrock, (2) bioturbated argillaceous mudrock, and (3) argillaceous claystone. These facies are interpreted as prodelta deposits intercalated with sediment deposited by settling from flood plumes. TOC is relatively high despite sedimentary dilution from deltaic input, indicating high primary productivity of organic matter at the time of deposition. TOC-rich accumulations comparable to the Haynesville Shale are observed in the Bossier Formation on Sabine Island and may exist wherever detrital sediment input has been reduced or diverted by currents. The lower Haynesville was deposited as an upwards-deepening succession during a second-order transgression that started after deposition of the Smackover Formation. Because the upper Haynesville was deposited as a sediment drift with an internally complex sedimentary geometry, no internal cyclicity is apparent, and the position of the second-order maximum flooding surface cannot be established. Deposition of the Bossier marks a significant turnaround when deltaic sediments prograded from the north and buried the mass-wasting and sediment-drift deposits. The distal setting of the facies, evidence of deposition below storm-wave base, the pelagic source of the sediment, and the sedimentary processes involved make application of sequence stratigraphic concepts to the deposits problematic.

Abstract The Haynesville Shale, an Upper Jurassic (Kimmeridgian) age calcareous and locally organic-rich mudrock, is one of many prominent shale gas plays in North America. As shale plays increase in importance, the ability to define basin-wide, robust, and stable stratigraphic frameworks using data derived from well-bores becomes increasingly critical. Here, the technique of chemostratigraphy is used to define a stratigraphic framework that extends through ten wells ranging from eastern Texas to northwestern Louisiana. Stratigraphic variations in inorganic geochemistry allow clear differentiation of Haynesville Shale from the underlying Smackover Formation, the Gilmer Lime, and the overlying Bossier Formation. More importantly, however, interpretation of the results allows two chemostratigraphic packages and four geochemically distinct units to be defined and correlated within the Haynesville Shale. The lithostratigraphic units are geochemically differentiated using variations in SiO 2 , Al 2 O 3 , MgO, Zr, and Nb, whereas the units within the Haynesville Shale are defined using changes in CaO, Al 2 O 3 , MgO, Fe 2 O 3 , Rb/K 2 O and Th/U values, and V enrichments. By integrating the geochemistry with x-ray diffraction and total organic carbon (TOC) results, it becomes apparent that the driving forces behind the changing geochemistry within the Haynesville Shale are the amounts of anoxia in the lower portion of the Haynesville Shale and of CaO input in the upper portion. Cyclical fluctuations in the relative abundances of Zr and Nb are interpreted to represent transgressive—regressive cycles—and provide enhanced correlation within the Haynesville Shale. By combining stratigraphic changes in Zr/Nb values with V enrichments, it is shown that the most severe period of anoxia is associated with the transgressive portion of the oldest cycle. Importantly, this suggests that this stratigraphic horizon is where maximum TOC can be expected. Lateral changes in geochemistry within the Haynesville Shale demonstrate that terrigenous input was highest in the northwest sector of the basin, primarily in East Texas, and anoxia was greatest in the east of the basin, primarily in Louisiana.

Abstract The Haynesville Shale in northwest Louisiana and east Texas is a geologically unique gas play in which many petrophysical, engineering, and mechanical properties are close to optimal. With high geopressure gradients ranging from 0.8 to >0.95 psi/ft and reservoir pressures ranging from 8000 to 17,000 psi, it is one of the most prolific shale-gas plays in North America. Through the use of horizontal wells and multiple-stage fracturing, gas production reached >7 Bcf/d in August 2011, and the play has surpassed the Barnett Shale in north Texas as one of the highest gas-producing plays in the United States. The objectives of this study are to investigate the effects of petrophysical, geochemical, geologic, mechanical, and engineering properties, as well as completion practices, on Haynesville Shale production. Core data show that connate water saturations range from 15 to 40% in the Haynesville. Low connate water saturation is attributed to water expulsion by oil and gas during hydrocarbon generation from organic matter within the shale. Nevertheless, slow fluid escape and gas generation at high temperatures resulted in an abnormally high reservoir pressure and pressure gradient, even in this relatively high porosity rock. The effects of the high geopressure gradient have been to increase reservoir pore pressure, to preserve porosity and permeability, and to enhance free gas content and the brittle nature of the gas shales. The average porosity of the Haynesville Shale is high, ~11%, and the free gas content is enhanced by high porosity and gas density. Because of the high formation pressures, effective stresses of the Haynesville are low, and laboratory compression tests show that the rocks are highly brittle at these low effective stresses. Production from the Haynesville is a complex function of geopressure gradient, effective stress, reservoir quality, and completion practices. A wide range of completion parameters, such as length of horizontal well, choke size, number of stages, and proppant volume, have been tested to find optimal production strategies. Large choke sizes, which increase initial potential, can have a detrimental effect on long-term production and smaller choke sizes lower the decline rates and increase long-term well productions. Initial potential and production are higher in the east and south regions with higher pressure, carbonate/silica content and total organic carbon than the northwest region in Texas with lower total organic carbon but higher clay content.

Abstract Petrophysical data collection in the Haynesville Shale in northwest Louisiana consists largely of wireline logging in vertical pilot wells with occasional coring. As in most gas shales, field development is primarily based on these data. Additionally, petrophysical and geologic data from vertical wells are assumed to be laterally consistent along the length of horizontal production wells. Typically these horizontal wells are logged solely with gamma-ray tools that are used for geosteering. However, both lateral and vertical variations in the geologic properties of shale have been demonstrated by core, laboratory, and wireline studies. Published research also suggests that lithofacies stacking pattern recognition is possible in these fine-grained sediments. An investigation has been undertaken in horizontal shale gas wells using a suite of gamma ray, resistivity (EWR), and azimuthal litho-density (ALD) logging-while-drilling (LWD) tools. One objective of this study was to determine if variation of lithofacies in shales could be detected using LWD tools. A proprietary petrophysical lithology model was developed from detailed core lithology descriptions of the Haynesville Shale. This model was applied to the LWD data collected along the lateral sections of four wells drilled in the Haynesville Shale. Vertical stacking patterns of lithofacies were observed in each of the Haynesville wells with this method. Lateral lithofacies variation within wells cannot be confirmed because of spatial and tool resolution issues. However, variation of lithofacies in a mappable stratigraphic interval between wells was observed. Study results appear to support previous research in shale geology and stratigraphy that suggest the recognition of lithologic and stratigraphic patterns can be applied to fine-grained sediments. This work demonstrates that the mapping of stratigraphic variability in shales may be possible by using LWD data in horizontal wells. In addition, lithofacies data generated in this investigation bring into question some of the assumptions generally applied in shale gas field development. The most significant of which is perhaps the idea that beds maintain consistent lithology along the typical lateral well path. In the last of the four wells presented in this report, gamma ray only geosteering was supplemented with input from other LWD sensors. This additional data appear to have improved lateral well targeting. The use of LWD tools beyond gamma ray in shale-gas formations could permit development of more realistic three-dimensional geologic models of shale reservoirs. In addition, these data could facilitate better well lateral placement, improved well completions, formation evaluation, and potentially increase well production and project economics.