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We have summarized the threefold significance of karst unconformity boundary: (1) The development of a sequence stratigraphic model for the Devonian Woodford Shale Formation is transferable to the Upper Wolfcamp in the Permian Basin, (2) demonstration of the more general application of that model beyond the Woodford to other resource shales, and (3) illustration of a modification of common sequence stratigraphy models specifically to unconventional resource shales. During early transgression, marine encroachment into the paleolows created anoxic, hypersaline marine “pockets” conducive to the preservation of organic matter. The result is deposition of thick, laterally discontinuous, organic-rich strata stratigraphically at or near the unconformity surface. This pattern of deposition and distribution of the organic-rich shale has been well-documented in the Devonian Woodford Shale and is applicable to other resource shales, in this case to the Permian Upper Wolfcamp Formation in the Central Basin Platform of the Permian Basin. The stratigraphy of the distribution of the Upper Wolfcamp on top of the Upper/Middle Wolfcamp Unconformity is similar to that of the Woodford, suggesting a similar origin and distribution. The resulting stratigraphy in both cases resembles that of the classical Exxon sea slug model except that rather than a single organic-rich deposit defining the condensed section and maximum flooding surface, a second organic-rich deposit occurs stratigraphically lower, at or near the unconformity surface. This theoretical summary can support the discovery of potential drillable target zones in the Woodford Shale and the Wolfcamp Shale.

Understanding and predicting the impact of lithofacies changes and structural effects on fracture distributions is vitally important to optimize a drilling location and orientation. To evaluate and model fracture intensity of the Late Ordovician-Silurian-Early Devonian Hunton Group carbonates in Oklahoma, natural fractures were studied at different scales using borehole images, three outcrops (two horizontally bedded outcrops and one anticline outcrop), and seismic data. Natural fractures identified from eight horizontal well borehole images include conductive (open), partially open, mineralized (closed), and induced fractures. Four fracture sets were identified from borehole images and from the two horizontally bedded outcrops. A 3D fracture intensity model was populated, from the fracture intensity logs at the boreholes, and compared with a 3D lithofacies model. Principal component analysis from lithology logs produced input to a self-organizing map to classify and cluster electrofacies. Thin sections and borehole images corroborate the electrofacies around the wellbores, whereas 3D seismic data were used as constraints to build a 3D lithofacies model. A 3D lithofacies model resulted from the extrapolation of the lithofacies from the well scale to the regional seismic scale. In this study area, lithofacies and structure are interrelated and control fracture distributions. Lithofacies is the primary control, whereas structure is the secondary control. Three lithofacies (wackestone, mudstone, and mud-dominated wackestone) were identified. A positive relationship between the fracture intensity and the presence of wackestone was observed at well locations and in the mapped subsurface area. The other two lithofacies do not exhibit high fracture abundance. Structural effects influence fracture distributions near faults and positive curvature areas in the subsurface measured on the 3D seismic data. For the Hunton Anticline outcrop exposure, there was a positive linear relationship between fracture intensity and changes in curvature for the mudstone and mud-dominated wackestone and an exponential relationship for the wackestone textures. The integration of lithology and structure from multidisciplinary, multiscalar data (i.e., outcrops, image logs, and 3D seismic) helps to identify and predict the fractured zones in the Hunton carbonates and can be used for horizontal well planning as well as stimulation programs. More importantly, this study proposes a generic model to predict the variability of fractures at different scales of curvatures combined with lithology changes and can be used for other carbonate reservoirs.

Subsurface natural fractures in shales are vital for fluid transport pre- and post-hydraulic fracturing in naturally fractured reservoirs such as the Woodford Shale. However, the dominant fracture sets that control the fluid flow in the subsurface are mostly unseen, and their intensity variation is unknown due to non-availability of image logs in most wells. In this paper, we have assessed the possibility of the existence of subsurface natural fractures in the Woodford Shale by understanding their generation history from outcrop and thin section studies. Additionally, we have addressed their relative abundance based on the bed thickness and composition. Out of the several fracture sets identified in the Woodford Shale, two joint sets (E-W and NE-SW) were interpreted as the oldest sets based on crosscutting and fill. These sets date back to before the Mid-Virgilian Arbuckle Orogeny and likely have different generation timings. The relatively silica- and carbonate-rich beds primarily contain the E-W fractures and the highly clay- and organic-rich beds mainly contain the NE-SW fractures. The E-W and NE-SW sets origins (both not related to local structural bending) are likely more numerous in the flat subsurface compared to fractures sets whose origins are related to structural bending. These two fracture sets probably also control the fluid flow in the subsurface. Younger fracture sets show more influence of local folding and are overrepresented in the outcrops with tilted beds. Therefore, they do not likely control relatively flat subsurface fluid flow. Although some fractures (fold or non-fold related) only have one type of cement or bitumen fill, others have two types of fills, i.e., bitumen along with another cement, or two types of cement (non-bitumen) indicating that these fractures underwent more than one stage of opening. Also, a negative correlation between fracture intensity and bed thickness, and a positive relationship between fracture intensity and quartz/carbonate content exist in the studied location.

This paper provides a comprehensive analysis and documentation of a popular outcrop (roadcut) of the Woodford Shale, known as the I-35 outcrop. At the bed scale, based on outcrop weathering responses, the lithology of the Woodford Shale is cyclically represented by two distinctive, intercalated rock types: soft (incompetent, ductile) siliceous shales and hard (competent, brittle) cherts. The detailed geologic characterization integrated results from several laboratory techniques: X-ray diffraction, X-ray fluorescence, total organic carbon (TOC), thin-section petrography, scanning electron microscopy, rock hardness, and uniaxial compressive strength (UCS) tests. Experimentally, soft beds are ductile because they sustained significant plastic deformation before failure on UCS tests; these beds are finely laminated, clay-rich ([Formula: see text]), have very high TOC content ([Formula: see text]), very high concentrations of organic proxies (Mo, U) and detrital proxies (Ti, Zr, K, Al), and low Si/Al ratios. In contrast, hard beds are brittle because they sustained little to no plastic deformation before failure; these beds are massive (not visibly laminated), quartz-rich ([Formula: see text]), and have lower TOC content ([Formula: see text]), lower organic proxies (Mo, U), and lower detrital proxies (Ti, Zr, K, Al). The results from our study attest the outcrop-based distinction between soft and hard beds, as determined by systematic contrasts in composition, rock fabric, and mechanical properties. In addition, our results provide insights for the prediction of rock properties for the two principal rock types within the Woodford Shale, giving rise to speculation that if a proper physical distinction is made between soft and hard beds in cores or outcrops, few samples would work well for upscaling rock properties within larger intervals with incomplete sets of data, thus helping to reduce the costs/time related to acquiring large data sets. In addition, observations from this and other outcrops indicate the potentially best horizontal targets are those with approximately equal proportions of the two rock types.

We have developed a detailed rock-based documentation of a previously undescribed Woodford Shale outcrop in South Central Oklahoma. The complete exposed section provided the opportunity to investigate lithologic attributes across the complete Woodford Shale thickness, as well as on its under- and overlying formational contacts. Within the Woodford Shale strata, seven lithofacies were recognized honoring textural and compositional attributes, and they were grouped based on their weathering response into soft (incompetent) and hard (competent) beds. Internally, across the Woodford interval, there is an overall upward increase in quartz content, represented by higher proportions of siliceous shales and chert around the middle and upper members, whereas the lower member is mostly dominated by organic and clay-rich shales interbedded with minor proportions of cherty beds. However, most notable was the rhythmic cyclicity between hard (brittle) and soft (ductile) lithofacies throughout the Woodford, from which systematic measurements of bed thickness and soft-to-hard ratios are examined to illustrate multiple scenarios of stratigraphic anisotropy. The geologic assessment of reservoir quality was assessed using the vertical arrangement of lithofacies, from which we hypothesized that potential target zones are interpreted to be composed by high-frequency interbeddings of organic-rich “soft” beds (acting as a local source) and “hard” brittle beds (acting as more frackable or fractured rocks). According to this model and the vertical stratigraphy, a potential target zone is interpreted to lie in between the upper half of the middle Woodford and lower half of the upper Woodford member, where the soft-to-hard ratio is approximately 50/50 and the beds are thinner.

Natural fracture aperture-size, spacing, and stratigraphic variation in fracture density are factors determining the fluid-flow capacity of low-permeability formations. In this study, several facies were identified in a Woodford Shale complete section. The section was divided into four broad stratigraphic zones based on interbedding of similar facies. Average thicknesses and percentages of brittle and ductile beds in each stratigraphic foot were recorded. Also, five fracture sets were identified. These sets were split into two groups based on their trace exposures. Fracture linear intensity (number of fractures normalized to the scanline length [[Formula: see text]]) values were quantified for brittle and ductile beds. Individual fracture intensity-bed thickness linear equations were derived. These equations, along with the average bed thickness and percentage of brittle and ductile lithologies in each stratigraphic foot, were used to construct a fracture areal density (number of fracture traces normalized to the trace exposure area [[Formula: see text]]) profile. Finally, the fracture opening-displacement size variations, clustering tendencies, and fracture saturation were quantified. Fracture intensity-bed thickness equations predict approximately 1.5–3 times more fractures in the brittle beds compared with ductile beds at any given bed thickness. Parts of zone 2 and almost entire zone 3, located in the upper and middle Woodford, respectively, have high fracture densities and are situated within relatively organic-rich (high-GR) intervals. These intervals may be suitable horizontal well landing targets. All observed fracture cement exhibit a lack of crack-seal texture. Characteristic aperture-size distributions exist, with most apertures in the 0.05–1 mm (0.00016–0.0032 ft) range. In the chert beds, fracture cement is primarily bitumen or silica or both. Fractures in dolomite beds primarily have calcite cement. The average fracture spacing indices (i.e., bed thickness-fracture spacing ratio) in brittle and ductile beds were determined to be 2 and 1.2, respectively. Uniform fracture spacing was observed along all scanlines in the studied beds.

Reservoir quality (RQ), commonly related to diagenesis, is important to predict formation porosity and permeability. The lack of studies to understand the role of diagenesis on tight reservoirs is a limiting factor for predicting petroleum accumulation in unconventional reservoirs. This study aims to determine the influence of diagenesis on RQ for the mixed carbonate-siliciclastic Sycamore Formation in southern Oklahoma. Additionally, this study assesses other geologic factors such as depositional facies control on diagenesis of the Sycamore. Petrographic observation, geochemical data, and conventional plug analysis from six cores and one outcrop were used to accomplish three objectives: i) reconstruct the paragenetic sequence; ii) determine the role of diagenesis on RQ; and iii) elucidate geological factors that control the diagenetic evolution in the Sycamore strata. Four facies were identified: Massive Calcite-cemented Siltstones, Massive Calcareous Siltstone, Bioturbated Mudstones, and Argillaceous Mudstones. However, this study focuses on the siltstones and their associated diagenetic processes and products. Porosity evolution in the siltstones is affected by cementation and dissolution processes. These diagenetic processes are related to each other; calcite cement decreases permeability during early diagenesis and controls the flow of later diagenetic fluids responsible for feldspar dissolution. Additionally, differences in the supply between a carbonate and siliciclastic material and a change from a carbonate-dominated system to a mixed system through time controls the distribution of calcite cement in the Sycamore. This study allows geologists to understand the diagenetic evolution and to characterize RQ of the Sycamore and similar formations by considering the sediment supply between carbonate- and siliciclastic-dominated systems, changes in stratigraphy, and influx of acidic fluids. Identifying geological controls on diagenesis and defining the influence of diagenesis on RQ in tight formations is important for the exploration and development of unconventional reservoirs, to build predictable porosity and permeability models, and to identify petroleum accumulations.

The Jackfork Group in Arkansas, U.S.A. is a major ‘training ground’ for academics, students, and petroleum industry geoscientists interested in deep water exploration and development. Several superb outcrop sections are exposed and over the years numerous papers have been published on these rocks. The Kirby sections in western Arkansas provide a unique opportunity to build a complete and continuous sequence stratigraphic framework for Early Pennsylvanian time in the ancient Ouachita Basin. There are 25 outcrops, including 12 roadcuts on Highway 27, and 13 measured sections in the Baumgartner Quarry. All the measurements and interpretations on the outcrops were integrated with previous work using modern concepts of deepwater turbidite geology, including (1) regional tectonic and sequence stratigraphic framework of the Stanley Group, Jackfork Group, and Johns Valley Shale in the Ouachita Basin, (2) deepwater outcrop characterization and correlation from the DeGray Lake Section, Dierks Section and Big Rock Quarry which are on the trend of the depositional fairway, (3) chemostrata data from key shale layers which are considered as potential correlative condensed sections. Twenty-five key shale samples from Kirby, DeGray and Dierks sections have been tested using Inductively Coupled Plasma and Mass Spectrometry (ICP-MS) tests. An additional 525 samples were later collected for Handheld X-Ray Fluorescence (XRF) tests for both major and trace elements. Results of sequence and chemostrata analysis indicate that the entire Kirby sections consist of at least three 3rd order sequences from the bottom of the Jackfork Group to the middle of the Johns Valley Group, and over ten 4th order sequences caused by a combined effect of tectonic uplift, eustatic sea-level change, mixed sediment provenance and shifting of depositional fairways when the Ouachita Basin was transitioning from a passive margin to a remnant marine basin. Rare Earth and Trace Element results are compared with known tectonic data to further pinpoint the tectonic environment of the Ouachita Basin during early Pennsylvanian time, which is dominantly a continental arc setting.

The Devonian Woodford Shale is a prolific unconventional resource shale for oil and gas. Like many such shales, the Woodford sits atop an unconformity on the surface of underlying carbonate rocks (mainly the Hunton Group in this case). There is variable topographic relief on the unconformity surface due to incised valleys, cave collapse, and/or karst formation during periods of subaerial exposure resulting from eustatic sea-level fluctuations. Anomalously high thicknesses of the Woodford, with relatively high total organic carbon (TOC), can form within topographic depressions on the unconformity surface, giving rise to potential “sweet spots” as drilling targets. It is likely that the topographic relief that formed during subaerial exposure created areas of restricted marine circulation (or possibly hypersaline lakes) during an early fall in the sea level, and thus, localized anoxic depositional environments conducive to preservation of organic matter (TOC). Seismic analysis, calibrated with well logs and cuttings, of two areas on the Cherokee Platform in Oklahoma were completed to test the discontinuous and isolated distribution, vertically and horizontally, of the TOC. In one area, the TOC ranged up to 10 wt.% and in the other area, up to 13 wt.%. Seismic inversion and attribute analysis demonstrated the patchy distribution of the TOC vertically and laterally in both areas. These patchy, discontinuous distribution spotlights areas where TOC was preserved (in the minibasins), and point to potential sweet-spot locations. The delineation of organic-rich sweet spots was accomplished by integrating geologic, geochemical, and geophysical data in probabilistic neural networks obtaining seismic impedance-derived TOC that was mapped across different locations in the Cherokee Platform.

The geological controlling factors of natural fracture distribution and density in the Woodford Shale Formation are quantitatively investigated in this study. The Upper Woodford Shale member in southern Oklahoma, is exceptionally brittle due to the abundance of recrystallized radiolaria chert beds that alternate with siliceous shale beds. Bed-bounded compressional fractures are well developed in the structural-active region. Two areas were characterized and compared to represent low and high confining pressure conditions respectively. A statistical analysis workflow consisting of Principal Component Analysis (PCA) and Partial Least Square Regression (PLS) was proposed to quantify the controlling factors' relationship and their Variable Importance in Projection (VIP) which reveals the contribution of each controlling factor to the fracture density. The result indicated that natural fractures' occurrence in shale reservoirs are impacted by three controlling factors: rock hardness, hard bed ratio (thickness percentage of hard beds within a stratigraphic unit interval) and bed frequency (number of beds within a unit interval). The contributions from these individual controlling factors are different under different reservoir conditions. Bed frequency (layering anisotropy) is the dominant controlling factor that contributes on average three times more than the hard bed ratio and hardness to fracture density. Hardness's contribution to fracture density in the subsurface scenario is lower by 22% than the surface scenario due to the increase in confining pressure. The analytical results highlight the importance of the layering effect on fracture density which has often been overlooked in geomechanical modeling workflow. A new concept of Fracture Density Index (FDI) is defined and can be further applied to predict fracture density in other unconventional reservoirs.

Comparing the concentration of molybdenum (Mo) (ppm) and total organic carbon (TOC) (wt%) within sediments allows interpretation of the relative degrees of bottom water restriction within the geologic record. The Woodford Shale is interpreted as transgressive systems tract (TST) grading into highstand systems tract (HST). The lowermost Woodford preserves a Mo-TOC signal that is consistent with a restricted basin that periodically received influxes of water consistent with rising sea levels flowing into restricted sub-basins that became isolated by localized conditions. The middle Woodford preserves a signal that indicates an increased ventilation at the sediment-water interface persisting until the maximum flooding surface. The presence of phosphate nodules in the uppermost Woodford suggests sufficient oxygen to retain the Mo in solution and indicates active upwelling and circulation with the Paleotethys. It is also possible to document changing ventilation patterns, non-destructively, within a basin by utilizing changing trends in redox-sensitive trace metals (Mo, Ni, and Cu) and an approximation of the degree of pyritization (aDOP) based on an idealized formula for pyrite (FeS2). This chemofacies approach produces a qualitatively similar interpretation to the changing Mo-TOC signal and can evaluate lateral trends in bottom water ventilation where destructive sampling is not permitted. Distal regions preserve the greatest degree of bottom water ventilation. Proximal regions preserve highly variable conditions with more restricted conditions being common in the lowermost Woodford Shale and ventilation improving upsection. Interpreting changing levels of bottom water anoxia enable greater degrees of precision in targeting potential hydrocarbon resources. Furthermore, this information improves our understanding of the changing environmental conditions of the Woodford Shale. The Framvaren Fjord is a reasonable modern analog for bottom water restriction in the lowermost portion of the Woodford Shale. The Cariaco Basin is a good modern analog for bottom water restriction in the middle and uppermost Woodford Shale.

Milliken’s (2014) classification scheme for fine-grained sediments and sedimentary rocks is an attempt to provide an improved classification that relies on interpreted grain origin to replace existing nomenclature schemes based on sedimentary structures, grain size, and composition. Milliken posits that existing terminology is confusing and therefore proposes new terms, viz. tarl, carl, and sarl, to define three main types of mudstone categories. We consider the proposed classification impracticable because there are: (a) ambiguities associated with interpreting grain origins (intrabasinal or extrabasinal), (b) difficulties in determining the original mineralogy of diagenetically altered particles, and (c) requirements for specialized equipment and techniques not widely available to many geologists. In our opinion, the proposed classification does not improve geological understanding over prior established classification approaches.

Petrographic analysis is based on the microscopic description and classification of rocks and is a crucial technique for sedimentary and diagenetic studies. When compared to hand specimens, thin sections provide better and more accurate means for analysis of mineral proportion, distribution, texture, pore space analysis, and cement composition. Most petrographic analysis relies on visual inspection of rock thin sections under a microscope, a task that is laborious even for experienced geologists. Large projects with a tight time frame requiring the analysis of a large amount of thin sections may require multiple petrographers, thereby risking the introduction of inconsistency in the analysis. To address this challenge, we explore the use of deep convolutional neural networks (CNN) as a tool for acceleration and automatization of microfacies classification. We make use of transfer learning based on robust and reliable CNN models trained with a large amount of non-geological images. With a relatively small number of labeled thin sections used in “fine-tuning” training we are able to adapt CNN models that achieve low error levels (

This paper presents an interpreted depositional environment, developed 2nd order sequence stratigraphy framework, and detailed lithofacies identification from two Mississippian Sycamore outcrops (I-35 Sycamore and Speake Ranch) and subsurface wells in the SCOOP (South Central Oklahoma Oil Province). Then these rocks calibrate the rock properties with wireline log responses to identify the best landing zones. Qualitative and quantitative techniques of field, laboratory, and machine learning studies were conducted. For the field studies, we measured the complete 450 ft of the outcrop stratigraphic section, another separate 50 ft outcrop, examined the underlying Woodford Shale and overlying Caney Shale boundary contacts, documented sedimentary structures, constructed an outcrop gamma-ray profile, and developed a sequence stratigraphic framework. Laboratory studies included petrographic analyses, detailed X-ray Fluorescence (XRF), Scanning Electron Microscopy (SEM), and X-ray Diffraction (XRD). For machine learning studies, a principal component analysis (PCA), elbow method, and self-organizing map (SOM) were used to analyze the electrofacies and chemofacies from the outcrop and a subsurface uncored well. The outcrop hand-held gamma ray profile was obtained and correlated with subsurface wells. Five major outcrop lithofacies and chemofacies, within six stratigraphic units of alternating siltstone and shale strata, were identified from the wireline logs. A Maximum Flooding Surface (MFS), and two major 2nd order Sequence Boundaries (SB) were recognized at the outcrop and a nearby subsurface well. Bouma sequences and repetitive cycles of sedimentary structures indicated sediment gravity flow deposition on a marine slope setting. This study provides geologic insights to better understanding the depositional environment and the lithology of the Sycamore rocks. The bioturbated siliceous shale and/or the sandy siltstone can be potential target zones due to their reservoir quality, lithology, bed continuity, and brittleness. This information can be of direct benefit to the exploration and development programs of many companies in the SCOOP area, particularly in the Anadarko and Ardmore basins in Oklahoma.

Optimal upscaling of a high-resolution static geologic model that reflects the flow performance of the reservoir is important for reasons such as time and calculation efficiency. In this study, we demonstrate that honoring reservoir heterogeneity is critical in predicting accurate production and reducing the time and cost of running reservoir flow simulations for the Hunton Group carbonate. We integrated three-dimensional (3D) seismic data, well logs, thin sections, multiscale fracture studies, discrete fracture networks, and geostatistical methods to create a 100 &times, 150 &times, 1 ft gridded representative geologic model. We calibrated our gridded porosity and permeability parameters, including the evaluation of fractures, by history matching the simulated production rate and cumulative production volumes from a baseline fine-scale model generated from petrophysical and production data obtained from five wells. We subsequently reperformed the simulations using a suite of coarser grids to validate our property upscaling workflow. Compared to our baseline history matching, increasing the horizontal grid cell sizes (i.e., horizontal upscaling) by factors of 2, 4, 8, and 16 results in cumulative production errors ranging from +0.5% for two time (2&times, ) coarser to +74.22% for 16&times, coarser. The errors associated with vertical upscaling were significantly less, i.e., ranging from +0.5% for 2&times, coarser to +10.8% for 16&times, coarser. We observed higher production history matching errors associated with natural fracture size. Results indicate that greater connectivity provided by natural fracture length has a larger effect on production compared to the higher permeability provided by larger apertures. We also estimated the trade-off between accuracy and run times using two methods: (a) using progressively larger grid cell sizes, (b) applying 1, 5, 10, and 20 parallel processes. Computation time reduction in both scenarios may be described by simple power law equations. Observations made from our case study and upscaling workflow may be applicable to other carbonate reservoirs.

Understanding mudrocks and shale reservoirs has become a significant area of interest within industry and academia in recent years. Of particular interest is understanding the pervasive variability present within these units. This variability became apparent when conventional approaches, such as lithostratigraphic analysis and well log correlation, were coupled with recent developments in palynostratigraphy and chemostratigraphy. A single shallow Woodford Shale research core in the western Arkoma Basin from Pontotoc County, Oklahoma, was used to identify three scales of stratigraphic cyclicity. By comparing the relative abundances of continental sourced pollen and spores to marine-derived acritarchs over a stratigraphic interval, it was possible to extrapolate the overall trends in shoreline trajectory. Conventional well log analysis, such as gamma ray logs, provided a balanced understanding of the interplay between localized changes in sedimentation and regional shifts in the stratigraphic base level, in addition to providing a means to tie these analyses to extensive subsurface data sets. Chemostratigraphic correlations resolved subtle, but stratigraphically significant, shifts in localized patterns in sedimentation. Using these approaches, the Lower and Middle Woodford Shale can be divided into four chemostratigraphic parasequences within a transgressive systems tract defined by well log and core analysis. The Upper Woodford can be separated into an additional four chemostratigraphic parasequences within a highstand systems tract. Chemostratigraphic data also revealed the changing bottom water conditions present at the time of deposition, with a period of localized anoxic conditions recorded in the Lower and Upper Woodford in this part of the basin. These localized changes in sedimentation and environmental conditions can be nested into two longer term regional transgressions and regressions.

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 argon-ion 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 anunpolished 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, butshale microfabric and non-organoporosity is best viewed under non-milled surfaces. Complete FESEM imagery for shale characterization should include both types of analyses.

Based on a sequence stratigraphic framework developed using gamma ray stacking patterns, we have identified brittle-ductile couplets, which allow us to better interpret the microseismic response recorded during a single-stage hydraulic fracture stimulation treatment monitored from three strategically located observation wells. We have analyzed and compared hydraulic fracturing results inferred by individual processing of microseismic data acquired from horizontal and vertical sensor arrays, as well as the results from simultaneously processing the signals recorded by all three sensors. Ultimately, we have decided in favor of the triple array simultaneous solution as the most useful data set to interpret the stimulation treatment due to the location of the microseismic events coupled with the theoretical expectation from our sequence stratigraphic framework. The final data set has not only allowed us to better interpret the hydraulic fracturing results, but also helped us improve recommendations in support of the field development campaign.

Geologic models built from well logs and natural fracture (NF) parameters obtained at shale and carbonate outcrops/quarries were employed in understand artificial hydraulic fracture (HF) propagation and stimulated reservoir volume (SRV) geometries. We applied field HF treatment parameters from an Arkoma Basin well, located 20–25 miles (32–40 km) east of the studied quarries. We matched the microseismic cloud (MC) geometries of three field stages, followed by sensitivity analyses of various HF treatment and reservoir parameters. Geometry matches reveal that the average NF permeability in the Viola Group Limestone is nearly eight times that in the Woodford Shale. The sensitivity analyses (forward modeling) disclosed several likely outcomes. First, a minor (5 × 10−6) increase in the minimum horizontal tectonic strain and ensuing increase in the minimum horizontal stress resulted in a sizeable transformation of the SRV geometry. Second, pumping at a higher net pressure (ISIP increased from 6500 to 7000 psi) diminished the stimulation volume and opened more previously non-dilatable NFs closer to the wellbore. Higher net pressure also triggered more stimulation downward and out of the target zone in the studied area. Third, halving the number of NFs and doubling their final storage apertures significantly magnified the fracturing-fluid efficiency (i.e., lowered leak off into NFs) in areas where it was restricted from flowing through non-dilatable NFs. Additionally, this modification caused greater lateral growth and comparatively large downward (out of target zone) growth of the HF and NF reactivation front, lowering the effectiveness of the HF job. However, halving the number of NFs and doubling their final storage apertures did not result in a substantial change in the SRV geometry upon allowing fluid flow through non-dilatable NFs. Fourth, altering the well-landing depth within the Woodford Shale did not result in a major shift in the overall stimulation geometry or volume. Most importantly, the simulated hydraulic fractures emanating from the wellbore do not span the entire recorded microseismic cloud length and height.

X-ray fluorescence (XRF) was applied to measuring drill cuttings in order to characterize reservoir heterogeneity along a horizontal wellbore that landed in the organic-rich Woodford Shale. The measured XRF data profile which is composed of different paleoenvironmental and sedimentary element proxies were interpreted along with microseismic data distribution patterns from hydraulic fracturing. Three representative microseismic event distribution patterns were selected as demonstrations for reservoir heterogeneity’s impact on hydraulic fracturing efficiency, reflected by the corresponding variation in the XRF profile. This case study indicates that heterogeneity is a non-negligible factor in unconventional shale reservoirs and controls the efficiency of hydraulic fracturing. XRF is not restricted to conduct vertical scale chemostratigraphic characterization on core and outcrop, but also applicable for lateral well heterogeneity characterization near wellbore, which helps optimizing hydraulic fracturing design and ultimately reducing the risk of production failure.

The area of influence of the Magdalena submarine fan, offshore northern Colombia, is a global frontier basin with sparse well control and only publically available 2D seismic from which to conduct exploration surveys. We have conducted a 2D seismic stratigraphic study to advance knowledge of the tectonostratigraphic evolution of this area and, furthermore, optimize exploration concepts to include stratigraphy and sedimentology to enhance such opportunities. Eight third-order seismic sequences from the early Miocene to Holocene comprise the stratigraphic record. Seismic character, thickness, and sedimentary processes vary in each sequence based on the area of deposition. Three geomorphologic areas are subject to deposition: the Tayrona depression, the undeformed central Magdalena fan and deformed wedges on either side of the fan. From oldest to youngest, sequences I to V represent bathyal paleo-environments that were deformed during the late Miocene Andean phase. Deformation of these sequences is thin skinned thrust sheets, where the main basal detachment corresponds to Oligocene shale. This deformation continued until the middle Pliocene, when sequence VI and VII were deposited on the Magdalena Fan mainly as mass transport and channel-levee deposits. Sequence VIII represents the record from early Pleistocene to the present time. From early Pliocene to present, erosion was mainly the product of submarine fan activity and bypass in areas of high slope, whereas for older deposits, erosion was caused by exposure to subaerial conditions. Superimposed on the third-order sequences are fourth-order sequences, which reveal a relative (tectonic-eustatic) sea level increase from Early Miocene to middle Late Miocene (Tortonian) time, followed by a lowstand event that extended until Holocene time. Potential reservoirs embedded within the sequences include sheet sands, channel fills, and levee-overbank. Other components of the petroleum system such as a mature source rock are still under debate.

The active continental margin of northern Colombia has been affected by interactions between the Caribbean and South American plates since the early Miocene onset of the Andean orogeny. Since late Miocene time the Magdalena River has built a large submarine fan (Magdalena submarina fan, MSF) into the Caribbean Sea. Compression along the plate boundary has generated imbricated thrust zones in the eastern and western parts of the fan, straddling a relatively undeformed central area. An evaluation of the grading stage (i.e., graded to out-of-grade continental margin [Ross et al., 1994, 1995]) was done for the east and west imbricated thrust zones, as well as for the undeformed central fan area by applying criteria developed by Pyles et al. (2011). The dataset used in this study includes side-scan sonar images of the modern seafloor, 12 two-dimensional seismic surveys, and piston core descriptions. The east and west deformed wedges correspond to the early stage of out-of-grade submarine deposition with slope irregularities restricting sediment flow to tortuous corridors (i.e., piggy-back basins). Two types of sediment flows predominate: (1) relatively constant parallel-to-ridge flows originating from the shelf and (2) short-term perpendicular-to-ridge flows controlled by ridge instability and slumping. The upward stacking pattern near the canyon mouths of piggy-back basins consists of MTDs, lobe sands, and channel fills. Deposition in the less deformed central fan corresponds to the late stage of an out-of-grade margin that is characterized by erosion and sediment bypass on the upper slope and deposition on the middle and lower slope. The angles of the upper, middle, and lower slopes range from 2.5°–3.5°, 1.5°–2.5°, and 0°–1.5°, respectively. There is no evidence of progradation beyond the central fan area shelf break and channelized features are mainly erosional. Channel-levee systems and mass transport deposits are common on the middle and lower slopes. The MSF system is a special example of an out-of-grade fan that is in the process of becoming graded; therefore, systematic features are typical of an out-of-grade end member in transition to an “intermediate-grade” member, making this an interesting setting for stratigraphic studies on an active margin.

Comparison of some Paleozoic and Mesozoic gas shales has revealed a generally common sequence stratigraphy, consisting of, from the base upward: combined sequence boundary/transgressive surface of erosion (SB/TSE) upon which sits a transgressive systems tract (TST) enriched in organic matter, then a somewhat ‘cleaner gamma-ray’ highstand or regressive systems tract (HST/RST). When resolvable, this stratigraphy occurs at 2nd, 3rd, and 4th order relative sea level cyclicity, forming couplets of relatively organic-rich (TST and condensed section-CS) and organic-poor (HST/RST) strata at these time scales. A higher order sequence stratigraphy can be developed for Mesozoic shales than for Paleozoic shales owing to greater biostratigraphic age resolution of the former. The higher frequency cycles are superimposed upon lower frequency cycles, giving rise to a complex stratigraphy of several couplets of differing thickness and distribution. These documented common characteristics provide the basis for a unifying, general sequence stratigraphic model for shales which can be utilized to identify, predict and map the most productive facies within a shale stratigraphic interval. There also are several commonalities in geochemistry of gas shales. Prolific gas shales are usually >200 ft (65 m) thick, contain >3% TOC, have Hydrogen Index values >350 mg HC/g, contain Type II kerogen and have organic maturity values >1.1% Ro. Organic-rich shales typically contain minerals such as pyrite and phosphates (apatite) and show biomarker ratios (pristane/phytane, steranes distribution, C13–C20 regular isoprenoids and C18 aryl isoprenoids) indicative of anoxic conditions during source rock deposition. In high maturity areas, there is a reversal in ethane isotope abundance owing to secondary cracking of hydrocarbons; such a reversal is normally associated with best gas production. Relative hydrocarbon potential (S1 + S2/TOC) is a geochemical parameter which reflects oxygenation conditions in the depositional environment. It can be related to relative sea level fluctuations within a sequence stratigraphic context. Understanding the sequence stratigraphy of shale provides a powerful tool not only for regional-to-local stratigraphic correlations from well logs and seismic reflection records, but also for high-grading stratigraphic intervals most favorable for preservation of organic matter and gas generation and storage.

The lower Pennsylvanian Jackfork Group in Arkansas has been the subject of studies, field trips, and publications for many years because of excellent outcrop exposures of different deep-water architectural elements. This latest study is focused on the Baumgartner Quarry located near Kirby, Arkansas, which exposes a series of vertical walls in three dimensions. This quarry has not been as well documented as other popular exposures, although three-dimensional (3-D) quarry faces exist, and the quarry strata comprise part of a complete 600-m (1970-ft)-thick near-continuous Jackfork stratigraphic sequence not unlike younger deep-water stratigraphic exploration targets in the Gulf of Mexico and elsewhere. Subsurface problems including reservoir uncertainties and reservoir performance of lobe versus channel-fill deposits are addressed based on our work in the quarry. A 3-D sequence-stratigraphic model was developed using a correlation of seven measured stratigraphic sections in the quarry. The 180-m (590-ft)-thick quarry strata consist of a lower lowstand systems tract (LST) (lower sandstones) dominated by channel-fill sandstones, overlain by a shaly transgressive systems tract (condensed section), and then by an upper LST (upper sandstones) dominated by sheet or lobe sandstones. This model was translated into an updip against salt field, which is analogous to some deep-water Gulf of Mexico reservoirs. Performance simulation was conducted on the model using a one-injector water well and two vertical producing wells, one of which was connected to the injector via a channel sandstone and the other of which was offset from the channel sandstone. Results yielded 60% more production from the connected injector-producer pair than from the nonconnected pair. Comparison between the lower (channel-prone) sandstones and the upper (sheet-prone) sandstones revealed that the sheet-prone sandstone is more sustainable, whereas the channel-prone sandstone exhibits a larger drop in production rate during a 10-yr production period. These results illustrate the value of 3-D outcrop models for reservoir performance simulation for development planning of deep-water fields with limited data control, such as in the deep-water Gulf of Mexico.

Ten Barnett Shale lithofacies have been recognized in a 223-ft (68-m)-long core from Johnson County, Texas. Eight of these lithofacies match those previously identified in the main producing area of the Newark East (Barnett Shale) field in the northern part of the Fort Worth Basin, but two new lithofacies have been identified in this core, resedimented spiculitic mudstone lithofacies and lag deposits, both of which are indicative of a relatively higher energy environment and downslope resedimentation of shallower water deposits. The recognition of cyclical stacking patterns of the lithofacies, condensed sections (CSs), and transgressive surfaces of erosion were the keys to establishing the sequence-stratigraphic framework in these fine-grained rocks, which consists of seven stratigraphic intervals in the lower Barnett Shale and nine stratigraphic intervals in the upper Barnett Shale. Spectral gamma-ray uranium and thorium logs aided in this objective and are recommended for future sequence-stratigraphic studies of these and other shales. The sequence-stratigraphic framework reveals that the lower Barnett Shale in this area was deposited mainly in a low-energy, relatively deep-water environment, somewhat far from a terrigenous source area, which probably lies to the northwest. By contrast, the upper Barnett Shale was deposited in an oxygenated shallower water environment, which had a source area from the west and southwest sides of the basin. The higher frequency of sea level fluctuation during development of the upper Barnett Shale most probably indicates periodic tectonic activity, perhaps associated with a structural high that was susceptible to sea level fluctuations. Alternatively, it could have resulted from the onset of glaciations in Gondwanaland during this time. This higher frequency may indicate that the upper Barnett is Chesterian in age, because cyclicity was higher than during the Osagean and Meramecian stages. If so, there may be more high-frequency cycles than recognized in this core. Siliceous sponge spicules are more common in this core than in more northerly cores, so more brittle facies might prevail in the southern part of the Fort Worth Basin. High gamma-ray log responses, which are caused by a high total organic carbon, and/or in-situ phosphate minerals are commonly found in CSs and can be used for regional correlations. However, high gamma-ray phosphatic deposits that have been resedimented to downslope positions by sediment gravity flows are an exception to the previous statement. Correlation of the Barnett stratigraphic intervals now provides a north-to-southeast stratigraphic framework along the Fort Worth Basin. Relative hydrocarbon potential (RHP) is an organic geochemical parameter applied to this core and found to provide an indicator of marine transgressions and regressions. We recommend continued testing and use of the RHP parameter for high-frequency sequence-stratigraphic analysis of unconventional gas shales.

A long held geologic paradigm is that mudrocks and shales are basically the product of ‘hemipelagic rain’ of silt- and/or clay-sized, detrital, biogenic and particulate organic particles onto the ocean floor over long intervals of time. However, recently published experimental and field-based studies have revealed a plethora of micro-sedimentary features that indicate these common fine-grained rocks also could have been transported and/or reworked by unidirectional currents. In this paper, we add to this growing body of knowledge by describing such features from the Paleozoic Barnett Shale in the Fort Worth Basin, Texas, U.S.A. which suggests transport and deposition was from hyperpycnal, turbidity, storm and/or contour currents, in addition to hemipelagic rain. On the basis of a variety of sedimentary textures and structures, six main sedimentary facies have been defined from four 0.3 meter intervals in a 68m (223 ft) long Barnett Shale core: massive mudstone, rhythmic mudstone, ripple and low-angle laminated mudstone, graded mudstone, clay-rich facies, and spicule-rich facies. Current-induced features of these facies include mm- to cmscale cross- and parallel-laminations, scour surfaces, clastic/biogenic particle alignment, and normal- and inverse-size grading. A spectrum of vertical facies transitions and bed types indicate deposition from waxing-waning flows rather than from steady ‘rain’ of particles to the sea floor. Detrital sponge spicule-rich facies suggests transport to the marine environment as hypopycnal or hyperpycnal flows and reversal in buoyancy by transformation from concentrated to dilute flows; alternatively the spicules could have originated by submarine slumping in front of contemporaneous shallow marine sponge reefs, and then transported basinward as turbidity current flows. The occurrence of dispersed biogenic/organic remains and inversely size graded mudstones also support a hyperpycnal and/or turbidity flow origin for a significant part of the strata. These processes and facies reported in this paper are probably present in other organic-rich shales.

The identification of organoporosity (microscale and nanoscale pores within organic matter in shales), its importance to storage and perhaps transfer of gas molecules through shales, and methods for gathering three-dimensional images of the pores, such as by argon-ion milling and/or field emission scanning electron microscopy, have all been well documented and discussed for unconventional gas shales. However, other types of pores exist within shales that can be important to storage and migration of gas (and oil), and other technologies are available for their identification and imaging. The different pore types found in the Barnett and Woodford shales are described and classified in this article. Scanning electron microscopy revealed the presence of porous floccules in both the Barnett and Woodford shales, which appear similar to laboratory-produced floccules and to those in other ancient shales. Published experimental and observational studies indicate that floccules are hydraulically equivalent to coarser grains and are transported by traction processes. Current-induced microsedimentary structures and textures within the Barnett and Woodford shales, as well as the preserved floccules, suggest such processes were active during transport and deposition. Pore spaces between the floccules are open and can provide storage space as well as permeability pathways for gas molecules through the shales. Pores are also found within organic matter that occurs both as discrete particles and as adsorbed coatings around clay grains in the shale. They are referred to here as “organopores.” Porous fecal pellets are also common in the Barnett Shale. Preserved fossil fragments such as organic-walled spores and inorganic sponge spicules have hollow central chambers, which may remain partially or completely open even after burial. Intraparticle pores occur between grains of various minerals (e.g., pyrite framboids). Microchannels within shale matrix, which may be the bounding surfaces of scours or microsedimentary structures, may also provide permeability pathways for hydrocarbon migration. Mircrofractures are also common, and their initiation might be related to mineral crystal structure. When present in sufficient quantity, these pore types offer potential gas (and oil) molecule storage spaces and permeability pathways through the shales.

Sand production is not uncommon in producing fields. Its severity, however, remains a growing concern in many mature fields and deepwater reservoirs often characterized by poor consolidation. Reservoir sand production is sim-ultaneously a source of concern and benefit in conventional and heavy oil production. Porosity increase and changes in local stress magnitude, which often enhance permeability, have been associated with severe sanding. On the other hand, sand production has been linked to a large number of field incidences involving loss of well integrity, casing collapse, and corrosion of downhole systems. It also poses problems for separators and transport facilities. The poorly consolidated Gudao reservoir in Shengli oil field, China, provides a typical example of casing failure, resulting from severe reservoir sanding (Figure 1). Sand-production-induced casing problems can vary from complete shearing to contortion of well casing depending on the severity of the sand flow.

The recent revelation of vast global quantities of potentially gas- (and oil-) productive shales has paved the way for rapid advancements in understanding their geological properties, many of which affect their geomechanical properties, and ultimately reservoir operations and performance. Because of shale's unique and very intricate geological, physical and mechanical properties at all scales (from nano- to macro-scale (Abousleiman et al., 2010) compared with sandstones and carbonates, the ad-jective “unconventional” has often been applied to their characterization. Although many shale characteristics are different than those of sandstones and carbonates, and require new technologies to measure them, other characteristics, mentioned below, are similar. As such, customized conventional methodologies and concepts can be applied to exploration and production of shale gas (and oil).

Stratigraphic grade is the similarity of the morphology of successive slope-to-basin profiles in a genetically related depositional system. In this article we use data collected from regional cross-sections of six depositional systems, stratal architecture derived from outcrops of the Lewis Shale (Wyoming, USA), and the Ross Sandstone (Ireland), and supplementary outcrop and subsurface data from other depositional systems to determine how stratigraphic grade relates to stratal (reservoir) architecture in deepwater systems. Four methods are developed that collectively define stratigraphic grade: (1) regional stacking patterns of fourth-order stratigraphic surfaces, (2) the relationship between the trajectory of the shelf edge (Tse) and the trajectory of the depocenter (Td) for fourth-order stratigraphic units, (3) morphology of the slope-to-basin profiles of fourth-order stratigraphic surfaces, and (4) the similarity of the morphologies of slope-to-basin profiles of fourth-order surfaces in a system (σs, σr). Several characteristics of stratigraphic (reservoir) architecture of fourth-order stratigraphic cycles are related to stratigraphic grade: (1) longitudinal distribution of sandstone in fourth-order cycles, (2) location of maximum sandstone relative to the depocenter of fourth-order cycles, (3) lengths of fourth-order submarine fans, and (4) longitudinal and vertical distribution of architectural elements. Stratigraphic grade is thus a predictor of reservoir architecture and can thereby be used to reduce the uncertainty in the interpretation of subsurface data. The concept of stratigraphic grade is useful in understanding the stratigraphic evolution of deepwater systems. Most deepwater systems analyzed in this study initiated as out-of-grade and temporally evolved to graded systems over a time span of millions of years. Systems rarely evolve from graded to out-of-grade. First-order controls on stratigraphic grade are determined to be angle of slope, tectonically forced changes in angle of slope during deposition, and sediment supply.

Detailed interpretation of seismic attributes along horizon slices or stratal slices reveals changes in depositional pattern and seismic geomorphology within a sediment column that are controlled by eustatic and local changes in sea level. In this study, we analyze seismic geomorphologic features of a shallow sedimentary column within a salt minibasin in the northern Gulf of Mexico, and attempt to predict the relative sea-level curves. We then calibrate these predictions against biostratigraphic markers and compare with existing eustatic cycles and events. Systematic analysis of amplitude and attribute data within a seismic geomorphologic framework reveals high-resolution sequence stratigraphic patterns that might otherwise be overlooked.