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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.

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 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.

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.

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.

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.

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.

Ground Penetrating Radar (GPR) provides a high resolution image of bed-scale features within the interior of an outcrop. This geophysical technique has been used successfully in fluvial-deltaic sequences, but its successful use in deepwater deposits is less documented. The present paper demonstrates the ability of GPR to define the nature of channel margins and to distinguish internal channel facies at turbidite outcrops in Wyoming (Cretaceous Lewis Shale), USA. Profiles obtained behind the Lewis Shale outcrops show channel-fills having complex, slumped margins between channel sandstones and adjacent levee thin-beds, as well as onlap of sandstone beds onto the channel margins. Within the channel-fill, facies distinguished by GPR vary from interbedded debris flows and turbidites on one side of a channel to cross-bedded sandstones on the other side. Lateral accretion surfaces and onlap features, which cannot be observed at the outcrop scale, are present on GPR profiles. They may represent cross-channel sediment transport and deposition within a sinuous channel. These examples suggest that, when used together with geologic mapping, photomosaics, and available behind-outcrop drilling and logging, GPR surveys spanning large outcrops may provide valuable sub-seismic scale architectural information for building more robust 3-D models of deepwater reservoirs. q 2003 Elsevier Ltd. All rights reserved.

Scanning electron microscopy (SEM) and thin-section analysis of the fabrics (particle orientation) of some well known ‘oil shales’ reveal they all share two common characteristics: (1) even though preferred platy particles dominate, there is present an open network of numerous interconnecting pores; and (2) fine lamination of alternating silt and organic clay-rich zones is common. Shales selected for analysis include the Woodford Shale, Sunbury Shale, torbanite, Rundle Shale and Ohio Shale (Huron Member), West Falls Formation (Rhinestreet Member), New Albany Shale (Clegg Creek Member) and the Exshaw Formation. A model is proposed, based upon fabric information, for the migration of hydrocarbons from source rocks. Hydrocarbons generated in organic-rich zones migrate through the micropores until reaching adjacent silt laminae, which act as ‘pipelines’ to facilitate further migration out of the source rock.

Uranium and copper concentrations were determined on 184 sediment samples collected systematically arount the periphery of 24 lakes in the Kaipokok region of Labrador. The results allowed us to define several zones across glacial drift and lake-covered terrain which are enriched in these elements and which warrant further exploration. Some zones are extensions of known U and Cu mineralization, but others had not previously been found. This survey demonstrates that systematic nearshore lake sediment sampling and geochemical analysis is an informative method of mineral exploration which can be used as a follow-up to reconnaissance level sampling.

Twenty-four samples of Late Wisconsin ice-cap till, which is locally derived from parent rocks of contrasting texture, were found to be different in composition but similar in texture. Comparison of this till with continental ice-sheet and valley glacier deposits suggest initial or limited comminution of rock by glacial action results in till consisting of a continuous spectrum of particle sizes regardless of parent rock type, although it is possible that the fundamental nature of the comminution process by ice-caps and valley glaciers differs from that by continental ice-sheets.