Abstract There are a variety of pore types in unconventional resource mudstones and shales. The currently preferred method by geologists and petrophysicists is to examine and analyze these mudstones and shales by argonion and focused ion-beam milling to produce an ultrasmooth surface, coupled with observation under the field emission scanning electron microscope (FESEM). Potential issues with Ar-ion milled/FESEM preparation and imaging include (1) the small size of sample cubes for upscaling, (2) loss of structural fabric during the milling–imaging process, (3) fewer non-inorganic pore types observed than when observed with an unpolished surface, (4) analog use of pores from one shale to another, although the pore types and composition might differ, and (5) the creation of potential artifacts related to desiccation and rock expansion because of core retrieval and sample preparation. Conventional FESEM images obtained from freshly broken surfaces reveal much more textural detail than those obtained from ion-milled (polished) surfaces. Although conventional FESEM methodology may share some of the same limitations as Ar-ion beam-milled/FESEM technology, FESEM methodology should not be overlooked because it provides a more cost-effective and potentially more accurate analysis for estimating porosity and determining pore types and their distribution in shales. Comparison of FESEM images from ion-milled and fresh, non-ion-milled surfaces reveals that organic matter and internal organoporosity are best viewed on ion-milled surfaces, but shale microfabric and non-organoporosity is best viewed under non-milled surfaces. Complete FESEM imagery for shale characterization should include both types of analyses.

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 Middle Devonian Geneseo Formation and its lateral equivalents in the Northern Appalachian Basin are regarded as crucial secondary targets to the extensively explored Marcellus subgroup. High-resolution sedimentology, stratigraphy, and petrography have yielded differentiation of genetically related packages, comprised of distinct lithofacies with characteristic physical, biological, and chemical attributes. In addition, argon ion milling and nanoscale scanning electron microscopy of shale sections has shown that the pore structure of the Geneseo derives from pores defined by phyllosilicate frameworks, carbonate dissolution, and within organic matter. Intervals of silt-rich mudstones and muddy siltstones occur in multiple facies types and “interrupt” facies, reflecting background sedimentation. These deposits and their sedimentary features are interpreted as products of high-density fluvial discharge events. Pore morphology and distribution correlates with distinct mudstone lithofacies as a result of small-scale compositional and textural characteristics. Phyllosilicate framework pores are small triangular openings (100-1500 nm wide) and are the dominant pore type observed in hyperpycnites. Organic matter porosity is common (10-500 nm pore size) and dominates the organic-rich facies that represents “background” sedimentation with high organic content. Carbonate dissolution pores (50-500 nm wide) are observed in calcareous intervals and reflect partial dissolution of carbonate grains during catagenetic formation of carboxylic/phenolic acids.

Abstract In 2006, Mark Papa, CEO of EOG Resources, Inc. directed EOG divisions to focus on identifying and leasing large acreage blocks in shale oil window fairways (Mark Papa, personal communication) in basins throughout the United States while subordinating all exploration for natural gas, and in particular, dry gas. The company’s strategic change to shale oil exploration occurred during what was referred to as a “wall of disbelief” (Birger, 2011) predicated on the premise that oil molecules could not flow through shale-dominated permeability systems. The EOG Garner 1054 C#1, drilled in November 1998, encountered hydrocarbons within the Eagle Ford Formation at a pressure gradient of 0.76 psi/ft, at a subsurface true vertical depth (TVD) of 9300 ft (2834.6 m). Although a wet gas producer, this well was a critical element in the rationale to obtain leases in the oil window of the Eagle Ford Formation. Predicated upon a technical analysis of additional vertical well production within the Eagle Ford Formation indicating the existence of a dual porosity, or matrix-supported flow network, and in conjunction with the generation of fairway criteria mapping, EOG initiated a leasing strategy resulting in the acquisition of 569,000 contiguous acres within the crude oil window fairway. Regional mapping of the Eagle Ford Formation was conducted to model structure, thickness, total organic carbon (TOC), thermal maturity (R o ), oil gravity, and hydrocarbon saturation as well as lithostratigraphic continuity, postulated environments of deposition, and mineralogical variations. An identified fairway situated between the Maverick Basin and the San Marcos arch, a syn-depositional graben system on the margin of a transgressed carbonate platform, was mapped as a relatively thick and laterally continuous stratigraphic section within the targeted R o , TOC, and favorable hydrocarbon saturation windows. X-ray diffraction (XRD) analysis revealed that while the silica content within the Eagle Ford Shale was low relative to the more topical Barnett Shale and other existing shale resource plays, the mineralogical constituents were that of a brittle carbonate with variable clay content replete with a deceptive gamma log signature as a consequence of elevated levels of uranium and thorium. Distinct structural settings displaying unique structural and stratigraphic attributes were recognized and mapped, all of which had remained within the oil generation window for the last 30 million years. Net rock volume increases associated with prolonged oil generation and expulsion were believed to increase the likelihood of catagenically induced micro-fracturing resulting in enhanced system permeability. Eight strategically located vertical delineation wells were drilled across a 15 by 120 mi (24.1 by 193.1 km) fairway located from Gonzales to LaSalle Counties. Conventional coring coupled with extensive electric logging suites and petrophysical evaluations provided an integrated regional understanding of the Eagle Ford Formation. Nanometer-scale imaging with focused ion beam (FIB) and field emission scanning electron microscopy (FESEM) of Eagle Ford core samples showed interconnected porosity systems and pore sizes capable of transmitting oil molecules. Initial production rates from EOG-operated horizontal delineation drilling confirmed the viability of the Eagle Ford Formation as an overpressured carbonate resource rock with system porosity and permeability capable of long-term economic oil production. The methods defined in this chapter were appropriate for the delineation of the oil window within the Eagle Ford of South Texas; however, hydrocarbon systems are unique and these methods may not be applicable for defining other plays within other basins.

Abstract A series of subsurface reservoir and geological properties are reviewed, specific to the Eagle Ford Shale of south Texas and compared with production trends. Currently, an area in excess of 7 million acres has been tested for Eagle Ford production potential by hydraulically fracture-stimulated, horizontal wellbores. The bulk of this area is suitably thick (>125 ft [38.1 m]), organic-rich (>2 wt. % total organic carbon), and attains a thermal maturity consistent with hydrocarbon generation for Type II kerogen (>435°C T max ). Production trends, highlighted by well performance analysis from over 1450 wells, point to a clear differentiation of an optimum fairway comprising a greater population of strong wells. This fairway represents approximately 10% of the aforementioned area. With this in mind, the significance of key geological properties and their heterogeneities are evaluated and discussed. Understanding well performance, and more importantly, the key drivers that govern well performance provide the motivation for this study. The results of this study highlight the fact that the best performing wells across the play (based upon initial 18-month cumulative production) are located within a narrow 7 mi (11.3 km) wide, SW–NE strike-orientated belt that extends across several counties spanning approximately 140 mi (225.3 km). This fairway in general parallels the ancestral lower Cretaceous shelf edges (Sligo and Stuart City) and is characterized by a thermal maturity window (460–500°C T max ) consistent with wet gas and condensate production. Structurally downdip of these margins the play transitions into dry gas. Moving updip to the north, lower levels of thermal maturity are encountered (i.e., early oil window) that deliver lower volume wells, presumably due to lower levels of kerogen conversion and transformation. Thermal maturity is one of the primary well performance drivers in the play. Across the central portion of the trend, within the optimum maturity window, local production sweet spots exist that are further delineated by a combination of higher reservoir pressure and the interaction of local depositional patterns that promote above-average accumulations of organic-rich facies. By contrast, a significant proportion of the poorer wells analyzed commonly display much higher values for clay content, even though many of these wells share favorable levels of thermal maturity, reservoir pressure, and moderate organic-richness. The elevated clay content (>30%) and resulting undesirable geomechanical properties restrict well performance. This is likely a function of limited stimulation effectiveness and/or proppant embedment. Clay content is the single most important metric that significantly degrades well performance, even when other parameters are favorable. This degradation can occur over a short distance (2-5 mi [3.2–8 km]) and is independent of most other variables. Wellbore-scale properties such as the occurrence of natural fractures appear to influence early time flow-back profiles, but have a modest influence on long-term well production. These variances represent smaller-scale perturbations that are superimposed upon the broader controls noted earlier.

Abstract With the onset of the shale revolution in the United States, understanding shale reservoir rock properties has become increasingly important. The criteria used to characterize these ultra-low-permeability shale reservoirs and their resource potential commonly include organic richness, thermal maturity, lithologic heterogeneity, formation brittleness, and porosity. Because the lateral continuity of these systems often changes rapidly over short distances, it is desirable to quantify changes in these criteria both vertically and laterally within the reservoir. Here we present three seismic techniques used to identify, characterize, quantify, and map spatial distributions and variations of key attributes. Using seismic attribute data calibrated to key wells, we focus the mapping of three key attributes over a large region in South Texas: mechanical facies (i.e., fracability), fracture intensity as it relates to reservoir pressure, and total porosity over a large region in south Texas. This approach to mapping source rocks may change the way ultra-low-permeability shale reservoirs are evaluated in the future.