Abstract Shale resource systems have had a dramatic impact on the supply of oil and especially gas in North America, in fact, making the United States energy independent in natural gas reserves. These shale resource systems are typically organic-rich mudstones that serve as both source and reservoir rock or source petroleum found in juxtaposed organic-lean facies. Success in producing gas and oil from these typically ultra-low-permeability (nanodarcys) and low-porosity (<15%) reservoirs has resulted in a worldwide exploration effort to locate and produce these resource systems. Successful development of shale-gas resource systems can potentially provide a long-term energy supply in the United States with the cleanest and lowest carbon dioxide-emitting carbon-based energy source. Shale-gas resource systems vary considerably system to system, yet do share some commonalities with the best systems, which are, to date, marine shales with good to excellent total organic carbon (TOC) values, gas window thermal maturity, mixed organic-rich and organic-lean lithofacies, and brittle rock fabric. A general classification scheme for these systems includes gas type, organic richness, thermal maturity, and juxtaposition of organic-lean, nonclay lithofacies. Such a classification scheme is very basic, having four continuous shale-gas resource types: (1) biogenic systems, (2) organic-rich mudstone systems at low thermal maturity, (3) organic-rich mudstone systems at a high thermal maturity, and (4) hybrid systems that contain juxtaposed source and nonsource intervals. Three types of porosity generally exist in these systems: matrix porosity, organic porosity derived from decomposition of organic matter, and fracture porosity. However, fracture porosity has not proven to be an important storage mechanism in thermogenic shale-gas resource systems. To predict accurately the actual resource potential, the determination of original hydrogen and organic carbon contents is necessary. This has been a cumbersome task that is simplified by the use of a graphic routine and frequency distribution (P50) hydrogen index in the absence of immature source rocks or data sets.

Abstract Success in shale-gas resource systems has renewed interest in efforts to attempt to produce oil from organic-rich mudstones or juxtaposed lithofacies as reservoir rocks. The economic value of petroleum liquids is greater than that of natural gas; thus, efforts to move from gas into more liquid-rich and black-oil areas have been another United States exploration and production paradigm shift since about 2008. Shale-oil resource systems are organic-rich mudstones that have generated oil that is stored in the organic-rich mudstone intervals or migrated into juxtaposed, continuous organic-lean intervals. This definition includes not only the organic-rich mudstone or shale itself, but also those systems with juxtaposed (overlying, underlying, or interbedded) organic-lean rocks, such as carbonates.Systems such as the Bakken and Niobrara formations with juxtaposed organic-lean units to organic-rich source rocks are considered part of the same shale-oil resource system. Thus, these systems may include primary and secondary migrated oil. Oil that has undergone tertiary migration to nonjuxtaposed reservoirs is part of a petroleum system, but not a shale-oil resource system. A very basic approach for classifying shale-oil resource systems by their dominant organic and lithologic characteristics is (1) organic-rich mudstones with predominantly healed fractures, if any; (2) organic-rich mudstones with open fractures; and (3) hybrid systems with a combination of juxtaposed organic-rich and organic-lean intervals. Some overlap certainly exists among these systems, but this basic classification scheme does provide an indication of the expected range of production success given current knowledge and technologies for inducing these systems to flow petroleum. Potential producibility of oil is indicated by a simple geochemical ratio that normalizes oil content to total organic carbon (TOC) referred to as the oil saturation index (OSI). The OSI is simply an oil crossover effect described as when petroleum content exceeds more than 100 mg oil/g TOC. Absolute oil yields do not provide an indication of this potential for production as oil content tends to increase as a natural part of thermal maturation. Furthermore, a sorption effect exists whereby oil is retained by organic carbon. It is postulated that as much as 70 to 80 mg oil/g TOC is retained by organic-rich source rocks, thereby limiting producibility in the absence of open fractures or enhanced permeability. At higher maturity, of course, this oil is cracked to gas, explaining the high volume of gas in various shale-gas resource systems. Organic-lean rocks, such as carbonates, sands, or silts, may have much lower oil contents, but only limited retention of oil as these rocks have much lower sorptive capacity. The presence of organic-lean facies or occurrence of an open-fracture network reduce the importance of the sorption effect. The oil crossover effect is demonstrated by examples from organic-rich but fractured Monterey, Bazhenov, and Bakken shales; organic-rich but ultra-low-permeability mudstone systems, such as the Barnett and Tuscaloosa shales; and hybrid systems, such as the Bakken Formation, Niobrara Shale, and Eagle Ford Shale, as well as Toarcian Shale and carbonates in the Paris Basin.

Abstract Based on recent studies of Barnett and Woodford gas shales in Texas and Oklahoma, a systematic characterization workflow has been developed that incorporates lithostratigraphy and sequence stratigraphy, geochemistry, petrophysics, geomechanics, well log, and three-dimensional (3-D) seismic analysis. The workflow encompasses a variety of analytical techniques at a variety of geologic scales. It is designed as an aid in identifying the potentially best reservoir, source, and seal facies for targeted horizontal drilling. Not all of the techniques discussed in this chapter have yet been perfected, and cautionary notes are provided where appropriate. Rock characterization includes (1) lithofacies identification from core based on fabric and mineralogic analyses (and chemical if possible); (2) scanning electron microscopy to identify nanofabric and microfabric, potential gas migration pathways, and porosity types/distribution; (3) determination of lithofacies stacking patterns; (4) geochemical analysis for source rock potential and for paleoenvironmental indicators; and (5) geomechanical properties for determining the fracture potential of lithofacies. Well-log characterization includes (1) core-to-log calibration that is particularly critical with these finely laminated rocks; (2) calibration of lithofacies and lithofacies stacking patterns to well-log motifs (referred to as gamma-ray patterns or GRPs in this chapter); (3) identification and regional to local mapping of lithofacies and GRPs from uncored vertical wells; (4) relating lithofacies to petrophysical, geochemical, and geomechanical properties and mapping these properties. Three-dimensional seismic characterization includes (1) structural and stratigraphic mapping using seismic attributes, (2) calibrating seismic characteristics to lithofacies and GRPs for seismic mapping purposes, and (3) determining and mapping petrophysical properties using seismic inversion modeling. Integrating these techniques into a 3-D geocellular model allows for documenting and understanding the fine-scale stratigraphy of shales and provides an aid to improved horizontal well placement. Although the workflow presented in this chapter was developed using only two productive gas shales, we consider it to be more generically applicable.

Abstract Changing confining stress can modify not only rock properties, such as porosity and permeability, but can also affect the ability of fluid to flow along planar mechanical discontinuities, such as faults, shear fractures, tensile cracks, or bedding planes. The degree to which the flow of fluids can be altered with varying confining stresses depends on the spatial orientation of the mechanical discontinuity and the strength of the rock. Similarly, if hydraulic fracture stimulation occurs in the vicinity of a mechanical discontinuity and the pressurized fracture fluids enter the discontinuity, then the high-pressure fluids can alter the effective stress on the mechanical discontinuity. These changes can cause the mechanical discontinuity to reactivate in shear, possibly resulting in an increase in the ability of the mechanical discontinuity surface to experience fluid flow, potentially diverting the stimulation fluids in a direction other than anticipated. A key component in the characterization of fluid flow along mechanical discontinuities is an understanding of the surrounding subsurface stress field. To constrain the present-day horizontal stress magnitude, a stress-strength equilibrium approach can be taken using overburden rock density estimation and information on the present-day tectonic setting. Horizontal stress orientation and magnitudes can also be inferred from structural geology principles via the interpretation of mapped active features and wellbore information, such as drilling history and image logs. Once information about stress magnitudes and orientation is available, one can calculate the shear and normal stress magnitudes acting on planar mechanical discontinuities of all possible orientations. Furthermore, one can evaluate what magnitude of fluid pressure within each mechanical discontinuity would be required to encourage shear failure reactivation. An example from the Barnett Shale play is presented here as an application of the method, offering various solutions to the likely orientations of fractures that could interact with hydraulic fracture treatment.

Abstract The Middle Devonian Marcellus Shale play is rapidly evolving into a major shale-gas target in North America with the potential to rival or exceed other established shale plays in terms of production rates, economic potential, and total extent. The Marcellus Shale is one of the largest shale plays in North America, with a potentially prospective area of approximately 114,000 km 2 (44,000 mi 2 ). Based on industry drilling trends and reported test rates, two major core areas have emerged, each with its unique combination of controlling geologic factors. The reserve potential for the play is enormous, with estimates ranging from 50 tcf to more than 500 tcf, defining the Marcellus Shale as a major world-class hydrocarbon accumulation. The organic-rich black shales of the Marcellus Shale were deposited in a foreland basin roughly paralleling the present-day structural front. The Marcellus Shale accumulated in an environment highly conducive to the production, deposition, and preservation of the organic-rich sediments. Key geologic and technical factors defining the Marcellus Shale play are similar to other shale-gas plays and include thermal maturity, reservoir pressure, play thickness, porosity, permeability, gas in place, the role of natural fracturing, mineralogy, depth, structural style, target landing issues, and the ability to be fractured. One key factor is reservoir pressure, as the Marcellus Shale benefits from a significant overpressured profile in the most prospective areas. The classification of structural setting and style is critical for the identification of natural fracture trends and potential geologic hazards that include faulting and fracturing in structurally complex areas. Since 2004, coinciding with the initial Marcellus discovery in Washington County, Pennsylvania, more than 7100 Marcellus wells have been permitted or drilled through June 2010 in the Appalachian Basin, and activity is expected to escalate during the next several years. Reported initial production rates for vertical wells range from 0.100 to more than 5.0 million cubic feet (gas) per day (mmcfpd) and from 0.300 to more than 26.000 million cubic feet (gas equivalents) per day (mmcfepd) for horizontal completions. Although the play is still in its infancy, reported production rates and reserves compare very favorably with other established North American shale plays.

Abstract Estimates of gas in place (GIP) for the Marcellus Shale can be calculated from analysis of the organic-rich rock by programmed pyrolysis. The GIP is a function of several factors, including the original hydrocarbon-generation potential of immature shale (S 2o ) as measured by programmed pyrolysis; a conversion factor (C) to determine the gas-volume equivalent generated by cracking of kerogen, bitumen, and oil; the thickness (t) of organic-rich shale; organic richness (O) compared with a standard sample; the transformation ratio (TR) of kerogen to hydrocarbon; and percent retention (R) of gas after primary migration. In particular, Technically recoverable reserves are computed to be 20% of the GIP. By way of example, our calculated GIP for Steuben County, New York, is 39 bcfg/mi 2 , and that for Broome County, New York, is 217 bcfg/mi 2 , a fivefold increase within 100 mi (161 km). Because geologic controls over GIP vary so greatly across the Appalachian Basin, gas resources and reserves should properly be calculated from local geochemical data.

Abstract The Upper Devonian and Lower Mississippian Bakken Formation in the United States part of the Williston Basin is a giant continuous (unconventional) oil resource. A recent U.S. Geological Survey (USGS) assessment estimated a mean volume of undiscovered technically recoverable oil for the Bakken Formation of about 3.65 billion bbl of oil. The estimate is based on a geologic model and a methodology that defines different assessment units by accumulation type (conventional or continuous), structural control, fracture occurrence and prediction, lithology and petrophysical properties, formation thickness, underlying salt movement or dissolution, and level of thermal maturity and oil-generation capacity of Bakken source rocks. The Bakken Formation consists of three informal members: (1) lower shale member; (2) middle sandstone member; and (3) upper shale member. Shale members are rich in marine organic matter (as much as 35% by weight) and are the petroleum source rocks, whereas the middle sandstone member varies in depositional facies and lithology and locally exhibits good matrix porosity (as much as 14%) but with low permeability, a characteristic of tight reservoirs. Additional commingled production occurs locally from matrix porosity in the immediately underlying, informally named, Sanish sand unit of the Upper Devonian Three Forks Formation. Combined, the Bakken Formation and Sanish sand define the Bakken composite continuous reservoir. On a larger scale, thermally mature organic-rich Bakken shale members are also the source for oils produced from locally occurring Waulsortian mounds or porous strata immediately above the upper shale member in the overlying Lower Mississippian Lodgepole Limestone. As a whole, elements of petroleum source, reservoir, seal, migration, and trap define the stratigraphic and geographic character of a Bakken-Lodgepole Total Petroleum System. The geographic extent of the continuous oil accumulation within the United States part of the Bakken Formation is defined as the area in which organic-rich shale members of the Bakken Formation are thermally mature with respect to oil-generation. The area of the oil-generation window for the Bakken Formation continuous reservoir was determined using a combination of the following: (1) contour mapping of both the hydrogen index (HI) and log-resistivity well data of the upper shale member, (2) calibration of HI to the transformation ratio (TR) from one-dimensional burial history models, and (3) calibration of HI to total organic content. The geologic model used to further define continuous assessment units (AUs) within the Bakken Formation continuous oil accumulation was, in general, based on assumed levels of thermal maturity and generation capacity of the Bakken shale members as determined from HI and TR, relation of HI and TR to potential fracturing and structural complexity of the Williston Basin, and lithofacies distribution and petrophysical character of the middle sandstone member. The area of the oil generation window was divided into five continuous AUs: (1) Elm Coulee-Billings Nose AU, (2) Central Basin-Poplar Dome AU, (3) Nesson-Little Knife Structural AU, (4) Eastern Expulsion Threshold AU, and (5) Northwest Expulsion Threshold AU. One hypothetical conventional AU, a Middle Sandstone Member AU, was defined external to the area of oil generation. Using the established U.S. Geological Survey methodology, assessment of each Bakken continuous AU was performed after estimation of effective well drainage areas, estimated ultimate recovery (EUR) from productive wells, and production success defined by a minimum EUR of 2000 bbl of oil. The AUs with the greatest resource potential are the Eastern Expulsion Threshold AU (mean volume, 0.973 billion bbl of oil), which is best represented by the Parshall and Sanish fields of Mountrail County, North Dakota, and the Nesson-Little Knife Structural AU (mean volume, 0.908 billion bbl of oil), where structural reservoir development exists, the middle sandstone member is thick and porous, the underlying Sanish sand reservoir unit is commonly present, and shale members have high oil-generation potential and the probability of abundant natural fracturing.

Abstract The Upper Cretaceous Milk River Formation in southeastern Alberta and southwestern Saskatchewan has produced more than 2 tcf of dry (>99% methane) microbial gas ( δ 13 C PDB –65 to –71‰) that was internally sourced. Production is from underpressured fine-grained sandstone and siltstone reservoirs, whereas the gas was generated in interbedded organic-bearing mudstones with low organic carbon contents (0.5–1.50%). The formation experienced a shallow burial history (maximum burial, <1.3 km [<0.8 mi]) and cool formation temperatures (<50°C [<122°F]). Petrologic and isotopic studies suggest that methanogenesis began shortly after deposition and continued for at least 20 to 25 m.y. Mercury injection capillary pressure data from the Milk River Formation and the overlying Upper Cretaceous Pakowki Formation, which contains numerous regionally extensive bentonitic claystones, reveal a strong lithologic control on pore apertures and calculated permeabilities. Pore apertures and calculated permeabilities in Milk River mudstones range from 0.0255 to 0.169 μm and less than 0.002 to 0.414 md, respectively, and claystones from the overlying Pakowki Formation have pore apertures from 0.011 to 0.0338 μm and calculated permeabilities of 0.0017 to 0.0065 md. The small pore apertures and low permeabilities indicate that claystones and mudstones served as seals for microbial Milk River gas, thereby permitting gas to accumulate in economic quantities and be preserved for millions of years. Based on the timing of gas generation, the gas system of the Milk River Formation can be considered an ancient microbial gas system, which is one of several ways it differs from that of the Devonian Antrim Shale, Michigan Basin, where microbial gas generation is a geologically young (Pleistocene and younger) phenomenon. The difference in timing of gas generation between the Milk River and Antrim systems implies that gases in the two formations represent end members of a spectrum of microbial gas accumulations in fine-grained rocks, with the Milk River Formation being an excellent example on which to base a paradigm for an ancient microbial gas system.

Abstract Carbonate-rich lithologies of the gas-producing Upper Mississippian Barnett Shale, Fort Worth Basin, Texas, are diverse and include lithologies with carbonate components that are primarily authigenic, as well as those that have carbonate components dominated by skeletal debris and other allochems such as peloids and intraclasts. Compositionally, carbonate-bearing lithologies of the Barnett Shale (including the informal unit known as the Forestburg Limestone) can be viewed as mixtures of authigenic or allochemical carbonate and siliciclastic sediment derived mostly from outside the basin. With the exception of the Forestburg Limestone, these varied carbonate lithologies dominate only in local zones, at the scale of a hand specimen or thin section, and do not constitute a volumetrically significant part of the gas-producing reservoir rock. Carbonate lithologies are significant, however, for clues they provide on environmental and early diagenetic conditions during accumulation of the Barnett Shale. Carbonate lithologies dominated by skeletal components contain distinct and impoverished marine faunas that are consistent with low oxygenation levels. The generally early timing of carbonate cement precipitation is supported by the reworking of diagenetic carbonate as silt- to sand-size intraclasts, sediment infilling of fractures in cemented beds and concretions, displacive fabrics, and highly random orientations of phyllosilicate grains within carbonate units. In some cases, detrital allochemical carbonates provided nucleation substrates for precipitation of highly displacive authigenic carbonate that was extensively reworked into microspar-size sediment particles. The elemental and isotopic chemistries of authigenic carbonates are consistent with near-sea-floor authigenesis driven by microbial cycling of organic carbon into carbonate minerals under generally reducing and low-temperature conditions.

Abstract Five lithologies are present in the Barnett Shale (Mississippian) in a core taken in Johnson County, Texas, in the southern part of the Fort Worth Basin. Dark claystone to mudstone makes up 86% of the cored interval. Sponge spicules are the most common silt-size grain in this lithology. The clay-size material comprising the matrix is a mixture of cryptocrystalline quartz, probably derived from radiolarian tests, and clay minerals. The rock is highly siliceous, hard, dense, and brittle. Three calcareous lithologies are present in the core: limy layers, shell layers, and concretions. Together, these lithologies make up only 7% of the cored interval. The limy layers and concretions consist almost entirely of micrite. The shell layers contain gravel-size fragments of brachiopods, pelecypods, and cephalopods. The calcareous lithologies are found as thin interbeds in the dark claystone to mudstone throughout the core. A laminated siltstone to mudstone containing abundant sponge spicules is found only at the top of the cored interval. Glauconite and phosphatic material are conspicuous components of this lithology. The phosphatic material includes phosphate-coated grains of glauconite, quartz, and fossil fragments. The lithologies in the core resemble those described in the core from the northern part of the basin. However, the relative abundance of the various lithologies changes greatly from the northern part to the southern part of the basin. Understanding lithologic variation within the Barnett Shale is key to locating sweet spots within the play and then selecting intervals within the reservoir in which to land horizontals wells.

Abstract A thick shale section cored in the EOG Resources Gordon saltwater disposal (SWD) well in the southern Fort Worth Basin contains six different lithologies. Gamma-ray readings on well logs can be used to distinguish the Barnett Shale (Mississippian) from the overlying Pennsylvanian shales and to divide the Barnett Shale into upper and lower units referred to informally as the Barnett A and Barnett B. Laminated silty claystone to mudstone is the dominant lithology in the Pennsylvanian shales above the Barnett Shale. The relative abundance of this lithology decreases downward in the core. It makes up a significant part of the Barnett A, but only a minor part of the Barnett B. A dark claystone shows the opposite trend, decreasing in relative abundance upward in the core. Sponge spicules are the most common silt- and sand-size grains in both the laminated claystone to mudstone and the dark claystone. Thin shell layers and phosphatic intervals are also found throughout the core. Shell layers are more common in the Pennsylvanian shales. Phosphatic material is most abundant in the Barnett B at the base of the core. Claystones and mudstones, lacking sponge spicules, but containing significant amounts of silt-size quartz are found only in the Barnett B. Isopach maps show that the Barnett B is part of a large shale wedge that prograded into the central and southern parts of the Fort Worth Basin from the northeast and that the Barnett A is part of a smaller shale wedge that prograded from east to west across Johnson County. The upper wedge onlaps and dies out against the flank of the lower wedge. The distribution of lithologies in the Gordon SWD well can be related to the position of the well site on the shale wedges. The site was far removed from areas of active sedimentation during the deposition of the Barnett B and closer to the main sources of sediment and areas of sedimentation during deposition of the Barnett A.

Abstract Shale reservoirs are continuous accumulations in which the same formation commonly serves as the source, reservoir, and seal for commercial accumulations of natural gas. Intrabasinal differences within continuous accumulations account for the indistinctly bound areas of better gas production termed sweet spots by operators. Generally similar sets of facies have been recognized in the Barnett Shale in the Fort Worth Basin by all recent workers. Dark mudstone to claystone with a matrix of clay minerals and cryptocrystalline quartz is the most common depositional facies in the Barnett Shale. Two predominantly calcareous depositional facies are next in abundance: argillaceous lime mudstone and skeletal argillaceous lime packstone. A variety of minor depositional and diagenetic facies are also present. The abundance and distribution of facies change with geographic location within the basin and stratigraphic position within the Barnett Shale. The most obvious example of this is the relative abundance of calcareous depositional facies in the northern part of the basin compared with their relative scarcity in the central part of the basin. All of the major facies recognized in the Barnett Shale have high concentrations of organic matter. The variation in facies is greater than the variation in organic matter content. The location of sweet spots with higher production rates within the Barnett Shale may ultimately be explained by the distribution of facies that respond differently to various completion procedures. As the play matures, it is likely that a detailed understanding of the geology, especially the distribution of facies, will become increasingly important in selecting well locations, intervals in which to land laterals, and which fracture stimulation techniques to use.

Abstract An outcrop-behind outcrop study was conducted in and adjacent to a 300 × 100 × 16 m (980 × 330 × 50 ft) quarry of the gas-producing Woodford Shale to structurally/stratigraphically characterize it from the pore to subregional scales using a variety of techniques. Strata around quarry walls were described and correlated to a 64 m (210 ft) long continuous core drilled 150 m (500 ft) back from the quarry wall and almost to the Woodford-Hunton unconformity. Borehole logs obtained include neutron and density porosity (NPHI and DPHI) logs, and logs from Elemental Capture Spectroscopy (ECS™), Combinable Magnetic Resonance (CMR-Plus™), Fullbore Formation MicroImager (FMI™), and sonic scanner (Modular Sonic Imaging Platform, or MSIP™)—all manufactured by Schlumberger. The strata around the quarry are horizontally bedded. Borehole logs were used to identify a basic threefold subdivision into an upper relatively porous quartzose interval; a middle, more clay-rich, and less porous interval; and a lower interval of intermediate quartz-clay content. These intervals correspond to the informally named upper, middle, and lower Woodford. Detailed core and quarry wall description revealed several types of finely laminated lithofacies, with varying amounts of total organic carbon (TOC). The FMI log revealed a much greater degree of variability in laminations than can be readily seen with the naked eye. Organic geochemistry and biomarkers are closely tied to these lithofacies and record cyclic variations in oxic-anoxic depositional environments, which correspond to relative sea level fall-rise cycles. At the scanning electron microscopy scale, microfractures and microchannels are common and provide tortuous pathways for gas (and oil) migration through the shales. Based on FMI and core analysis, fracture density is much greater in the upper quartzose lithofacies than in the lower, more clay-rich lithofacies. A laser imaging detection and ranging (LIDAR) survey around the quarry walls documented two near-vertical fracture trends in the quartzose lithofacies: one striking N85°E with spacings of 1.2 m (4 ft) and the other striking N45°E related to the present stress field. The FMI analysis only imaged the latter fracture set. Both log-derived and laboratory-tested geomechanical property measurements documented a significant relationship between shale fabric (laminations and preferred clay-particle orientation) and rock strength, and a secondary relationship to mineral composition. Porosity and microfractures or microchannels also appear to influence rock strength. This integrated study has provided insight into the causal relations among Woodford properties at a variety of scales. In particular, a stratigraphic (vertical) segregation of lithofacies can be related to cyclic variations in depositional environments. The resulting stratified zones exhibit variations in their hydrocarbon source and reservoir (fracturable) potential. Such information and predictive capability can be valuable for improved targeted horizontal drilling into enriched source rock and/or readily fracturable reservoir rock in the Woodford and perhaps other gas shales.

Abstract The sequence-stratigraphic framework established for the subsurface Barnett Shale in the northern part of the Fort Worth Basin is helping to resolve the age, nature, and fill of karst features under the Barnett Shale in the southwestern part of the basin. The southwestern Fort Worth Basin is characterized by the absence of the Upper Ordovician Viola Limestone and Simpson Group, which separate the lower Barnett Shale from the underlying Ordovician Ellenburger Group, as well as the Forestburg Limestone, which separates the upper and lower Barnett Shale to the north. Consequently, the undifferentiated Barnett Shale unconformably overlies the water-bearing Ellenburger Group and results in a higher risk of water encroachment during stimulation and production of Barnett gas wells. Recent work indicates that Barnett Shale parasequence sets dominated by phosphatic and siliceous shale lithofacies are more organic rich and possibly more gas prone than other Barnett lithofacies. Moreover, the quartz- and carbonate-rich lithofacies are brittle and appear to respond more favorably to hydrofracture stimulation and the facies with high amounts of clay may serve as a possible barrier for fracture propagation because of ductile behavior. Thus, the ability to locate and map these parasequence sets was a particularly important part of this study for aiding in reservoir characterization. Analysis of three-dimensional seismic data southwest of the core area of the Newark East field demonstrates the ability to identify and map Barnett parasequence sets previously defined from core and logs in the more northerly part of the basin. In addition, high-resolution seismic images of the karsted Ellenburger Group unconformity surface reveal a series of elongate, rectilinear, collapsed paleocave systems resulting from subaerial exposure and carbonate dissolution. These features appear to have shaped the unconformity surface and to have had a direct influence on the deposition and distribution of the overlying Barnett Shale parasequence sets. The parasequence sets are thicker over these collapsed features than in areas flanking the karst. The difference in thickness diminishes with each stratigraphically younger parasequence set, indicating focused infilling over the collapsed features caused by progressive reduction in accommodation space. Seismic analysis also reveals that the karst topography on the unconformity surface is related not only to local faulting caused by the paleocave collapse, but also to deep-seated northwest–southeast-trending faults that extend upward to the Ellenburger surface and sometimes into the overlying Barnett Shale, suggesting post-karst fault movement. Magnetic surveys over the area support the deeper origin of the fault pattern observed in the study area. In the Newark East field, the Viola Limestone and Simpson Group form a fracture barrier for the overlying Barnett Shale. Their absence to the southwest presents a dilemma—whereas the Barnett Shale is thicker over this area, the lack of a fracture barrier risks water encroachment from the underlying Ellenburger Group. Understanding Ellenburger karst development and behavior and how fault and fracture systems are associated with these structures is critical for comprehending the distribution and depositional pattern of the Barnett Shale parasequence sets. Moreover, the seismic mapping and characterization of the different parasequence sets (ranging in lithofacies and rock property) would allow improvement in selecting horizontal targets and fracture stimulation of Barnett gas wells.

Abstract A method is described for reservoir characterization in fine-grained and thinly bedded shales based on a probabilistic clustering procedure (PCP) of well logs followed by a forward modeling procedure that results in the calculation of profiles for porosity, water saturation (Sw), and permeability. The credibility of results relies on calibration using porosity, permeability, and mineralogy analyses of core samples. Complementary analysis using a nuclear spectroscopy log, if available, can add confidence to the results. Kerogen needs to be included during the forward modeling because it is a matrix component of the bulk rock and the matrix grain density (GD) can be significantly affected by kerogen. Kerogen profiles can be estimated if kerogen core analyses are included in the PCP. In addition, a total organic carbon (TOC) profile, which is needed to determine the amount of adsorbed gas, can be estimated based on core analyses of TOC. The relationships between TOC and kerogen, including a discussion of Rock-Eval pyrolysis, are outlined. The estimation of free gas gross pay in gas shales is fraught with difficulty because of the vagaries of estimating porosity and Sw. Although not realistic in terms of gross storage capacity, the use of the combination of total porosity (TPOR) and total water saturation (Swt) gives the same pay as the combination of effective porosity (EPOR) and effective water saturation (Swe). However, the combination of EPOR and Swt is ill-construed and results in underestimation of gross pay. The estimation of adsorbed gas in gas shales relies on a methodology and equations adopted from the coalbed methane industry. The workflow is easily implemented, but the credibility of results hinges on the assumption that the adopted methodology and equations are valid for gas shales, and on having sufficient and proper laboratory-derived gas adsorption isotherm measurements to represent the TOC heterogeneity of the reservoir. An example is given using analysis of a cored well from the Upper Jurassic Haynesville Shale of northwestern Louisiana and northeastern Texas. The analysis generated profiles for TPOR and EPOR, Swt and Swe, permeability, and net feet of pay.