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  • American Chemical Society  (451,325)
  • American Institute of Physics (AIP)  (241,953)
  • American Association of Petroleum Geologists (AAPG)  (92,962)
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  • 1
    Publication Date: 2019-05-16
    Description: Euphorkanlide A (1), a highly modified ingenane diterpenoid with a C24 appendage forming an additional hexahydroisobenzofuran-fused 19-membered macrocyclic bis-lactone ring system was isolated from the roots of Euphorbia kansuensis. Its structure was determined by extensive spectroscopic analysis and quantum-chemical calculations. Compound 1 showed significant cytotoxicities against a panel of cancer cell lines (IC50s 〈 5 μM). Mechanistic study revealed that 1 could induce the generation of ROS, leading to cell cycle arrest and cell apoptosis in drug-resistant cancer cell line HCT-15/5-FU.
    Type: Article , PeerReviewed
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  • 2
    Publication Date: 2019-03-12
    Description: Author Posting. © American Chemical Society, 2019. This article is posted here by permission of American Chemical Society for personal use, not for redistribution. The definitive version was published in Kivenson, V., Lemkau, K. L., Pizarro, O., Yoerger, D. R., Kaiser, C., Nelson, R. K., Carmichael, C., Paul, B. G., Reddy, C. M., & Valentine, D. L. (2019). Ocean Dumping of Containerized DDT Waste Was a Sloppy Process. Environmental Science and Technology (2019), doi:10.1021/acs.est.8b05859.
    Description: Industrial-scale dumping of organic waste to the deep ocean was once common practice, leaving a legacy of chemical pollution for which a paucity of information exists. Using a nested approach with autonomous and remotely operated underwater vehicles, a dumpsite offshore California was surveyed and sampled. Discarded waste containers littered the site and structured the suboxic benthic environment. Dichlorodiphenyltrichloroethane (DDT) was reportedly dumped in the area, and sediment analysis revealed substantial variability in concentrations of p,p-DDT and its analogs, with a peak concentration of 257 μg g–1, ∼40 times greater than the highest level of surface sediment contamination at the nearby DDT Superfund site. The occurrence of a conspicuous hydrocarbon mixture suggests that multiple petroleum distillates, potentially used in DDT manufacture, contributed to the waste stream. Application of a two end-member mixing model with DDTs and polychlorinated biphenyls enabled source differentiation between shelf discharge versus containerized waste. Ocean dumping was found to be the major source of DDT to more than 3000 km2 of the region’s deep seafloor. These results reveal that ocean dumping of containerized DDT waste was inherently sloppy, with the contents readily breaching containment and leading to regional scale contamination of the deep benthos.
    Description: This material is based upon work supported by the National Science Foundation Graduate Research Fellowship for V.K. under Grant No. 1650114. Expeditions AT-18-11 and AT-26-06 were funded by the NSF (OCE-0961725 and OCE-1046144). Any opinions, findings, and conclusions or recommendations expressed in this material are those of the author(s) and do not necessarily reflect the views of the National Science Foundation. We thank the captain and crew of the RV Atlantis, the pilots and crew of the ROV Jason, the crew of the AUV Sentry, the scientific party of the AT-18-11 and AT-26-06 expeditions, Justin Tran for assistance with the preparation of multibeam data, M. Indira Venkatesan for a helpful discussion of the NOAA datasets, and Nathan Dodder for advice on the procedure for compound identification.
    Repository Name: Woods Hole Open Access Server
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  • 3
    Publication Date: 2019-06-11
    Description: The vast amount of plastic waste emitted into the environment and the increasing concern of potential harm to wildlife has made microplastic and nanoplastic pollution a growing environmental concern. Plastic pollution has the potential to cause both physical and chemical harm to wildlife directly or via sorption, concentration, and transfer of other environmental contaminants to the wildlife that ingest plastic. Small particles of plastic pollution, termed microplastics (〉100 nm and 〈5 mm) or nanoplastics (〈100 nm), can form through fragmentation of larger pieces of plastic. These small particles are especially concerning because of their high specific surface area for sorption of contaminants as well as their potential to translocate in the bodies of organisms. These same small particles are challenging to separate and identify in environmental samples because their size makes handling and observation difficult. As a result, our understanding of the environmental prevalence of nanoplastics and microplastics is limited. Generally, the smaller the size of the plastic particle, the more difficult it is to separate from environmental samples. Currently employed passive density and size separation techniques to isolate plastics from environmental samples are not well suited to separate microplastics and nanoplastics. Passive flotation is hindered by the low buoyancy of small particles as well as the difficulty of handling small particles on the surface of flotation media. Here we suggest exploring alternative techniques borrowed from other fields of research to improve separation of the smallest plastic particles. These techniques include adapting active density separation (centrifugation) from cell biology and taking advantage of surface-interaction-based separations from analytical chemistry. Furthermore, plastic pollution is often challenging to quantify in complex matrices such as biological tissues and wastewater. Biological and wastewater samples are important matrices that represent key points in the fate and sources of plastic pollution, respectively. In both kinds of samples, protocols need to be optimized to increase throughput, reduce contamination potential, and avoid destruction of plastics during sample processing. To this end, we recommend adapting digestion protocols to match the expected composition of the nonplastic material as well as taking measures to reduce and account for contamination. Once separated, plastics in an environmental sample should ideally be characterized both visually and chemically. With existing techniques, microplastics and nanoplastics are difficult to characterize or even detect. Their low mass and small size provide limited signal for visual, vibrational spectroscopic, and mass spectrometric analyses. Each of these techniques involves trade-offs in throughput, spatial resolution, and sensitivity. To accurately identify and completely quantify microplastics and nanoplastics in environmental samples, multiple analytical techniques applied in tandem are likely to be required.
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  • 4
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    American Chemical Society
    In:  Environmental Science & Technology, 53 (9). pp. 5151-5158.
    Publication Date: 2019-08-28
    Description: Microplastics (MPs) in aquatic organisms are raising increasing concerns regarding their potential damage to ecosystems. To date, Raman and Fourier transform infrared spectroscopy techniques have been widely used for detection of MPs in aquatic organisms, which requires complex protocols of tissue digestion and MP separation and are time- and reagentconsuming. This novel approach directly separates, identifies, and characterizes MPs from the hyperspectral image (HSI) of the intestinal tract content in combination with a support vector machine classification model, instead of using the real digestion/separation protocols. The procedures of HSI acquisition ( 1 min) and data analysis (5 min) can be completed within 6 min plus the sample preparation and drying time (30 min) where necessary. This method achieved a promising efficiency (recall 〉98.80%, precision 〉96.22%) for identifying five types of MPs (particles 〉0.2 mm). Moreover, the method was also demonstrated to be effective on field fish from three marine fish species, revealing satisfying detection accuracy (particles 〉0.2 mm) comparable to Raman analysis. The present technique omits the digestion protocol (reagent free), thereby significantly reducing reagent consumption, saving time, and providing a rapid and efficient method for MP analysis.
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  • 5
    Publication Date: 2019-08-28
    Description: Latest knowledge on the reactivity of charged nanoparticulate complexants toward aqueous metal ions is discussed in mechanistic detail. We present a rigorous generic description of electrostatic and chemical contributions to metal ion binding by nanoparticulate complexants, and their dependence on particle size, particle type (i.e., reactive sites distributed within the particle body or confined to the surface), ionic strength of the aqueous medium, and the nature of the metal ion. For the example case of soft environmental particles such as fulvic and humic acids, practical strategies are delineated for determining intraparticulate metal ion speciation, and for evaluating intrinsic chemical binding affinities and heterogeneity. The results are compared with those obtained by popular codes for equilibrium speciation modeling (namely NICA-Donnan and WHAM). Physicochemical analysis of the discrepancies generated by these codes reveals the a priori hypotheses adopted therein and the inappropriateness of some of their key parameters. The significance of the characteristic time scales governing the formation and dissociation rates of metal−nanoparticle complexes in defining the relaxation properties and the complete equilibration of the metal− nanoparticulate complex dispersion is described. The dynamic features of nanoparticulate complexes are also discussed in the context of predictions of the labilities and bioavailabilities of the metal species.
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  • 6
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Fluvial-dominated deltas are common along modern and ancient coasts and act as important hydrocarbon reservoirs. In this paper, an integration of high-resolution three-dimensional seismic, well log, and core data are employed to investigate the seismic geomorphology, depositional facies, reservoir types, and controlling factors of fluvial-dominated delta deposition in the lower segment of the Minghuazheng Formation (N〈sub〉1〈/sub〉m〈sub〉L〈/sub〉), Bohai Bay Basin, China. Three typical seismic facies and seismic geomorphologic units are identified. Seismic facies 1 displays discrete high-amplitude reflection and a distinct U-shape incision. In plan form, this seismic facies shows a linear, dendritic, and sinuous morphology with high root-mean-square amplitudes. Seismic facies 2 occurs interspersed with seismic facies 1 and shows low-frequency and low-amplitude reflection. Seismic facies 3 shows a continuous high-amplitude reflection and uniform sheet-like morphology covering more than 10 km〈sup〉2〈/sup〉 (〉3.86 mi〈sup〉2〈/sup〉). The N〈sub〉1〈/sub〉m〈sub〉L〈/sub〉 was primarily deposited in the upper delta plain, lower delta plain, and delta front environments and is dominated by three major facies types: (1) distributary channel (seismic facies 1), (2) interdistributary bay (seismic facies 2), and (3) sheet sand (seismic facies 3). Among them, the distributary channel sandstones and sheet sandstones are the major reservoirs in the N〈sub〉1〈/sub〉m〈sub〉L〈/sub〉. Fluvial processes and lake level cycles were important factors in the development and distribution of reservoirs and traps in fluvial-dominated delta systems. Integration of the seismic geomorphology and a modern geomorphology investigation provide an effective way to predict the sandstone reservoirs and traps in fluvial-dominated delta systems.〈/span〉
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  • 7
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉For both modeling and management of a reservoir, pathways to and through the seal into the overburden are of vital importance. Therefore, we suggest applying the presented structural modeling workflow that analyzes internal strain, elongation, and paleogeomorphology of the given volume. It is assumed that the magnitude of strain is a proxy for the intensity of subseismic scale fracturing. Zones of high strain may correlate with potential migration pathways. Because of the enhanced need for securing near-surface layer integrity when CO〈sub〉2〈/sub〉 storage is needed, an interpretation of three-dimensional (3-D) seismic data from the Cooperative Research Centre for Greenhouse Gas Technologies Otway site, Australia, was undertaken. The complete 3-D model was retrodeformed. Compaction- plus deformation-related strain was calculated for the whole volume. The strain distribution after 3-D restoration showed a tripartition of the study area, with the most deformation (30%–50%) in the southwest. Of 24 faults, 4 compartmentalize different zones of deformation. The paleomorphology of the seal formation is determined to tilt northward, presumably because of a much larger normal fault to the north. From horizontal extension analysis, it is evident that most deformation occurred before 66 Ma and stopped abruptly because of the production of oceanic crust in the Southern Ocean. Within the seal horizon, various high-strain zones and therefore subseismic pathways were determined. These zones range in width from 50 m (164 ft) up to 400 m (1312 ft) wide and do not simply follow fault traces, and—most importantly—none of them continue into the overburden. Such information is relevant for reservoir management and public communication and to safeguard near-surface ecologic assets.〈/span〉
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  • 8
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Calcite cementation has been identified as an active process in the Upper Triassic Yanchang Formation throughout its burial history and as a major diagenetic factor causing strong reservoir heterogeneities. The origins of calcite cements and their relevance to reservoir heterogeneities were investigated using a suite of petrographic and geochemical methods, including optical microscopy with fluorescence and cathodoluminescence, scanning and backscattered electron microscopy with energy-dispersive spectrometry, x-ray diffraction, x-ray fluorescence, electron probe microanalysis, quantitative evaluation of minerals by scanning electron microscopy, fluid inclusion analysis, and carbon and oxygen stable isotope analyses. The sandstones are compositionally immature with relatively high amounts of volcanic rock fragments. The two generations of calcite cements are Ca-I and Ca-II. The Ca-I calcites are distributed along the interface of sandstone and mudstone units and were formed during the Late Triassic to Early Jurassic at formation temperatures of approximately 90°C. The Ca-II calcite mainly developed in the lower part of the fining-upward sandstone units and was formed in the Late Jurassic at higher temperatures of approximately 110°C. The origins of calcite cements were constrained by geochemical and isotope measurements, fluid inclusion homogenization temperature, and in situ element analysis. The Ca-I calcite cement originated from dissolution of the lacustrine depositional carbonates in the interbedded mudstones and reprecipitation in the adjacent sandstones. The Ca-II calcite was mainly related to organic matter decarboxylation, with Ca〈sup〉2+〈/sup〉 having been provided internally by volcanic fragment alteration and plagioclase dissolution. Calcite cementation had caused strong reservoir heterogeneities in the Yanchang Formation tight sandstones. The Ca-I calcite cementation destroyed reservoir properties along the interface of sandstones and mudstones. The lower parts of the fining-upward sandstone units were tightly cemented by Ca-II calcite, although they originally had high porosity and permeability. The middle–upper parts of the fining-upward sandstone units contain less calcite cements and thus have better preserved reservoir pores because of oil emplacement inhibiting the calcite cementation processes.〈/span〉
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  • 9
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Natural fractures are important storage spaces and fluid-flow channels in tight-oil sandstones. Intraformational open fractures are the major channels for fluid flow in tight-oil sandstones. Small faults may provide fluid-flow channels across different layers. According to analogous outcrops, cores, and borehole image logs, small faults and intraformational open fractures are developed in the tight-oil sandstones of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China. Among them, high dip-angle intraformational open fractures are the most abundant. Northeast-southwest–trending fractures are the principal fractures for fluid flow because that is the present-day maximum horizontal compressive stress direction. Combined with production data, horizontal wells, striking normal to or at a large angle relative to the major flow pathways, are beneficial for tight-oil production improvement. Fractures with high dip angles are the main factor that influences initial oil production. Linkage and tip damage zones are more favorable for oil production improvement than wall damage zones. This study provides an example of natural fracture characterization and unravels fracture contributions to reservoir physical properties and oil production of tight-oil sandstones, which could provide a geological basis for oil exploration and development in tight sandstones.〈/span〉
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  • 10
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Tectonic forces generated during thrust emplacement along active margins may drive complex fluid-flow patterns in fold-thrust belts and foreland basins. Isotope data (δ〈sup〉2〈/sup〉H and δ〈sup〉18〈/sup〉O) of fluid inclusions hosted in calcite vein cements are used to reconstruct regional fluid migration pathways in the Albanide fold-thrust system. The calcite veins used in this study developed in a sequence of naturally fractured Cretaceous–Eocene carbonate rocks as a result of episodic throughput of fluids from the early stages of burial onward. The acquired fluid inclusion isotope data demonstrate that fluids circulating in the carbonates were derived from an underlying reservoir that consisted of a mixture of meteoric water and evolved marine fluids, probably derived from deep-seated evaporites. The meteoric fluids infiltrated in the hinterland before being driven outward into the foreland basin and ascended as soon as fracturing induced a sufficient increase in permeability. Structural and petrographic observations provide time constraints for the various phases of fracture infilling and reveal an increasing dominance of meteoric water in the system through time as migration pathways shortened and marine formation fluids were progressively flushed out. Similar fluid-flow evolutions have previously been recorded in various fold-thrust belt settings elsewhere in the world.〈/span〉
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  • 11
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Thermal properties of rocks are essential parameters for investigating the geothermal regime of sedimentary basins, and they are also important factors in assessments of hydrocarbon and geothermal energy resources. The Tarim Basin, the largest basin located in the north of the Tibetan Plateau, northwestern China, has great hydrocarbon resource potential and is an ongoing target for industry exploration. However, the thermal properties of sedimentary rocks within the basin are yet to be systematically investigated at a basin scale, thereby limiting our understanding of the thermal regime in the basin. Here, we collected 101 samples of sedimentary rocks and measured their thermal properties. Our results show that the ranges (and means) of thermal conductivity, radiogenic heat production, and specific heat capacity are 1.08–5.35 W/mK (2.52 ± 0.99 W/mK), 0.03–3.24 μW/m〈sup〉3〈/sup〉 (1.24 ± 0.87 μW/m〈sup〉3〈/sup〉), and 0.75–1.10 kJ/(kg·°C) (0.87 ± 0.07 kJ/(kg·°C)), respectively. Volumetric heat capacity and thermal diffusivity at the temperature of 40°C range from 1.61 to 2.79 MJ/(m〈sup〉3〈/sup〉·K) (2.26 ± 0.25 MJ/[m〈sup〉3〈/sup〉·K]) and 0.44–2.95 × 10〈sup〉−6〈/sup〉 m〈sup〉2〈/sup〉/s ((1.12 ± 0.53) × 10〈sup〉−6〈/sup〉 m〈sup〉2〈/sup〉/s), respectively. The thermal properties vary considerably for different lithologies, even within the same lithotype, indicating that thermal properties alone cannot be used to distinguish lithology. Thermal conductivity increases with increased burial depth, density, and stratigraphic age, suggesting the dominant influence is porosity variation on thermal conductivity. Furthermore, a strong contrast in the thermal properties of rock salt and other sedimentary rocks perturbs the geothermal pattern, which should be taken into consideration when performing basin modeling.〈/span〉
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  • 12
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉A subaqueous clinoform system has been identified from high-quality three-dimensional seismic data from the northeast Exmouth Plateau, North West Shelf, Australia, and was interpreted as a shelf–slope–basin clinoformal component of a Jurassic fluviodeltaic system (the Legendre delta). Several geomorphological features associated with shelf-slope development and subsequent rift tectonics were identified, including (1) submarine channels at slope to basin floor; (2) gullies on the slope; (3) slumps on the shelf; and (4) canyons, canyon-derived gravity flow deposits, and a fan lobe developed in subsequent rift processes.The results of this study provide insights into the controlling factors on the sinuosity, degree of erosion, and sediment gravity flows of channels developed at slope to basin-floor settings, which shed light on the way fluvial sands were transported across the shelf and slope to the basin floor. The geometries and distributions of gravity flow deposits, if confirmed by drilling, may serve as an analog for reservoir prediction in the deep-water fluviodeltaic settings. The gullies on the slope were interpreted as a result of dilute, sheetlike flows. The slumps on the shelf were interpreted as a result of nonslope-related causes.The syntectonic canyons, the canyon-derived gravity flow deposits, and the fan lobe present vivid examples of the erosion and sedimentation processes during active rift tectonics and have significant implications for understanding the rift processes of the North West Shelf, Australia, as well as other rift-related basins.〈/span〉
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  • 13
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Substantial amounts of petroleum were recently discovered in the Carboniferous andesite, tuff, breccia, and basalt reservoirs of the Chepaizi uplift in the western Junggar Basin. However, the charging history of the Carboniferous petroleum reservoir is poorly understood. Oil–oil correlation studies indicate that all of the oils were mainly derived from the middle Permian Wuerhe Formation source rocks, possibly mixed with a small contribution from Carboniferous Baogutu Formation source rocks in the neighboring Changji sag. Based on the petrographic and microthermometry of fluid inclusions, two hydrocarbon charging episodes are defined; these episodes were characterized by a low-peak-range homogenization temperature (〈span〉Th〈/span〉) distribution (80°C–90°C) and high salinity (13.22–13.42 wt. % NaCl) and a high-peak-range 〈span〉Th〈/span〉 distribution (120°C–130°C) and low salinity (4.89–11.72 wt. % NaCl), respectively. Through one-dimensional basin modeling and pressure–volume–temperature–composition simulation, the burial-thermal histories for wells P61, P66, P668, and P663 were reconstructed, and their trapping temperatures of the hydrocarbon inclusions were calculated to be higher than their corresponding highest paleotemperature (i.e., 56.8°C, 53.7°C, 60.9°C, and 58.1°C, respectively), implying fast hydrocarbon charging processes promoted by deep hydrothermal fluids. Associated with the hydrocarbon generation history, sealing process of the Hongche fault, and regional tectonic evolution, these two hydrocarbon charging events were deduced as the adjustments of oils previously accumulated along the Hongche fault zone, because of the tectonic extension in the Paleogene and regional tilting in the Neogene, respectively. The general direction of oil charging was traced from south to north and from east to west, as indicated by the molecular parameters of nitrogen-bearing compounds and C〈sub〉20〈/sub〉 + C〈sub〉21〈/sub〉 triaromatic steroids/C〈sub〉20〈/sub〉 + C〈sub〉21〈/sub〉 + C〈sub〉26〈/sub〉–C〈sub〉28〈/sub〉 triaromatic steroids (TA(I)/TA(I+II)), which roughly coincided with the active fracturing.〈/span〉
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  • 14
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Modern oil and gas seismic surveys commonly use areal arrays that record continuously, and thus routinely collect “excess” data that are not needed for the conventional common reflection point imaging that is the primary goal of exploration. These excess data have recently been recognized to have utility not only in resource exploration but also for addressing a diverse range of scientific issues.Here we report processing of such discarded data from recent exploration surveys carried out in southeastern New Mexico. These have been used to produce new three-dimensional (3-D) seismic reflection imagery of a layered complex within the crystalline basement as well as elements of the underlying crust. This enigmatic basement layering is similar to that found on industry and academic seismic reflection surveys at many sites in the central United States. Correlation of these reflectors with similar features encountered by drilling in northwestern Texas suggest that they may be part of an extensive, continental-scale network of tabular mafic intrusions linked to Keweenawan rifting of the igneous eastcentral Unites States during the late Proterozoic. More importantly, this analysis clearly demonstrates that the new generation of continuously recorded 3-D exploration datasets represent a valuable source of fresh information on basement structure that should be examined rather than discarded. Such basement information is not only important to understanding crustal evolution, it is directly relevant to assessing risks associated with fossil fuel extractions, such as induced seismicity related to waste water injection.〈/span〉
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  • 15
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The White River watershed encompasses four major tributaries within a basin area of 130 km〈sup〉2〈/sup〉 (1595 mi〈sup〉2〈/sup〉) in extreme northwestern Nebraska. An examination of the historical (1968–1975) aqueous geochemistry data (major cations and anions and total dissolved solids [TDS]) supplied by the Nebraska Department of Environmental Quality revealed that the TDS is relatively low (130–1200 mg/L), excluding Big Cottonwood Creek (BCC), with a basin-wide median of 340 mg/L. The median TDS for the BCC is 1880 mg/L (brackish); the median values for Na and SO〈sub〉4〈/sub〉 are 385 and 897 mg/L, respectively. Mineralization in the river increases steadily downstream. The scatter plots of meq/L concentrations for selected anions and cations reveal the impact of silicate mineral (e.g., feldspar) weathering on the aqueous geochemistry throughout the watershed. These ubiquitous feldspar minerals most likely originated along the eastern slope of the Front Range during the Late Cretaceous and Tertiary (Laramide orogeny). Twenty-nine samples for three White River stations and the BCC exceed the US Environmental Protection Agency secondary maximum contaminant levels for TDS and/or SO〈sub〉4〈/sub〉 in drinking water supplies at 500 and 250 mg/L, respectively. Uncontaminated streams that drain marine shales (typically containing S-bearing minerals) nationwide typically show an excess of Na and a deficiency of Ca and Mg. This is due in part to cation exchange of Ca in solution for Na on clay minerals. Consequently, the weathering of shale terrains commonly produces an Na-SO〈sub〉4〈/sub〉 brackish surface-water runoff as is the case with BCC, which drains the Pierre Shale hills.〈/span〉
    Print ISSN: 1075-9565
    Electronic ISSN: 1526-0984
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  • 16
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Groundwater is the major source of drinking water in both urban and rural India. Estimation of natural groundwater recharge is essential for the sustainable development of groundwater. Natural recharge was estimated by various methods, such as the water level fluctuation method, water balance method, linear regression model, and nonlinear regression model. The recharge estimates by the water balance method was compared with the recharge obtained from the water level fluctuation method for the study area and found to be in good agreement.Estimation of recharge by the water level fluctuation method is laborious, and envisaging the difficulties in the availability and reliability of data, the water balance method is taken as the standard for developing regression equations in the present study. Simpler linear and nonlinear regression models were developed for the study area to estimate natural recharge by correlating with the water balance model. The models were calibrated with 10-yr data and validated with 5-yr data. The statistical analysis showed that no significant difference exists between the recharge estimate by the water balance method and the two estimates of natural recharges, such as linear regression and nonlinear regression models. The average recharge percentages from the water level fluctuation method, water balance method, linear regression model, and nonlinear regression model are 15.09%, 14.92%, 14.62%, and 14.57%, respectively, for the watershed during the study period. The study proves that regression equations can be efficiently used in recharge computation with proper calibration for ungauged basins, and laborious data-intensive computation methods can be eliminated.〈/span〉
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  • 17
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉In the past, determination of rock properties using image analysis relied upon petrographic transmitted-light images, but with limited success because of a lack of resolution and restricted computer processing power. A new technique that employs confocal laser scanning microscopy (CLSM) can be considered complementary to laboratory measurements and applicable to several samples, saving time and money and requiring only a limited amount of rock sample for analysis. We have studied several types of rocks with CLSM and fluorescent dye–impregnated thin sections. The two-dimensional scans of each thin section images is an area of 12 mm〈sup〉2〈/sup〉, with a pixel size of 0.198 µm and were used to simulate capillary pressure curves for pore bodies and pore throats. The CLSM technique also enables three-dimensional (3-D) visualization of the rock porosity. The studied rock samples were taken from diverse oil and gas field reservoirs: case A, a conventional sandstone (15.1% porosity, 29.8 md permeability); case B, a tight sandstone (3.7%, 0.02 md); case C, an oolitic carbonate (9.6%, 0.1 md); case D, a rhodolithic algal carbonate (19.8%, 43.7 md); case E, dolomitized carbonate (17%, 21.7 md); and case F, a naturally fractured carbonate (2.4%, 0.6 md). Our results confirm that the CLSM technique can be applied to rocks of contrasting porosity and permeability to obtain computed synthetic capillary pressure curves faster than with conventional measurement methods. The technique quantifies different pore-body and pore-throat sizes and distributions, with the added ability to visualize 3-D porosity and to extract from thin section analysis petrologic properties.〈/span〉
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  • 18
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Late Cretaceous–to–present-day mixed carbonate–clastic deposition along the Nicaraguan platform, western Caribbean Sea, has evolved from a tectonically controlled, rifted upper Eocene shallow–to–deep-marine carbonate–siliciclastic shelf to an upper Miocene–to–present-day tectonically stable shallow-marine carbonate platform and passive margin. By integrating subsurface data of 287 two-dimensional seismic lines and 27 wells, we interpret the Cenozoic stratigraphic sequence as 3 cycles of transgression and regression beginning with an upper Eocene rhodolitic–algal carbonate shelf that interfingered with marginal siliciclastic sediments derived from exposed areas of Central America bordering the margin to the west. During the middle Eocene, a carbonate platform was established with both rimmed reefs and isolated patch reefs. A late Eocene forced regression produced widespread erosion and subaerial exposure across much of the platform and was recorded by a regional unconformity. The Oligocene–upper Miocene sedimentary record includes a southeastward prograding delta of the proto-Coco river, which drained the emergent area of what is now northern Nicaragua. The late Miocene–to–present-day period marks a period of strong subsidence with the development of small pinnacle reefs. We describe favorable petroleum system elements of the Nicaraguan platform that include (1) Eocene fossiliferous limestone source rocks documented as thermally mature in vintage exploration wells and seen as active gas chimneys emanating from inferred carbonate reservoirs; (2) upper–to–middle Eocene reservoirs in patch and pinnacle reefs, middle Eocene calcareous slumps, and Oligocene fluvial-deltaic facies documented in wells; and (3) regional seal intervals that consist of both regional unconformities and Eocene–Oligocene intraformational shale.〈/span〉
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  • 19
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The three-dimensionally complex, highly progradational mixed siliciclastic–carbonate strata of the San Andres and Grayburg Formations have long been the backbone of conventional hydrocarbon reservoir production from the Permian Basin, and significant recovery continues via waterflooding and CO〈sub〉2〈/sub〉 injection. Besides, nonreservoir equivalents of these formations have recently taken increasing significance as produced water disposal targets. However, seismic-stratigraphic interpretations are challenged by complex internal shelfal-stratal geometries and numerous laterally continuous but vertically thin fluid barriers in overlying platforms. We built a three-dimensional (3-D) geocellular model of Guadalupian 8–13 high-frequency sequences (G8–G13 HFSs) and then conducted forward seismic modeling (35-Hz 0° phase). This allows investigations on the validity of applying conventional reflection-geometry–based interpretation to delineate the G9 HFS top and base, which can potentially serve as bounding/constraining surfaces for upper San Andres shelf–Grayburg platform reservoirs. This study contributes to 3-D modeling methodologies by introducing a query tree to select geostatistical methods for modeling dual-scale heterogeneities and by integrating data from diverse sources for seamless and realistic 3-D models. Our seismic-stratigraphic evaluation demonstrates that conventional reflection–geometry-based interpretation does not adequately resolve the G9 top and base; deviations from the geocellular model reach up to 80 m (260 ft) and are thus well beyond the maximum acceptable error limits of ±0.5 wavelength. We suggest improving conventional interpretations of the G9 base by selective interpolation or mixed-polarity event picking near the error-prone shelf margin and upper slope. Besides, instead of picking the highly discontinuous seismic peak as G9 top, bulk-shifting of a shallower trough horizon near actual G10 top should deliver a more accurate surface representing G9 top.〈/span〉
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  • 20
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The Paleogene shale of the Dongying depression, a continental basin in eastern China, is taken as the study subject to examine the microscopic features of lacustrine shale reservoirs in the oil window. This study shows that shale pores in this evolutionary stage are present at the micrometer to nanometer scale, but fractures commonly have extension distances at the millimeter scale. Pores and fractures can be divided into three types, namely, primary pores, secondary pores, and cracks. Primary pores commonly have good connectivity at shallow burial depth. With the increase of burial depth, primary porosity is reduced because of compaction and cementation. Secondary pores are important in shale, including dissolved pores inside grains and at grain edge, and dissolution pores inside the hybrid of organic matter (OM) and clay minerals, and evaporite minerals, including carbonates or sulfates. Types of cracks were observed: bedding fissures, dissolution fractures, and structural fractures. The development of bedding fissures is related to the deposition of shale laminae. The formation of dissolution fractures is related to acidic fluids, such as organic acids and hydrogen sulfide, whereas the formation of structural fractures is jointly controlled by fault development, fluid overpressure, and lithofacies. The pores and fractures in the oil window of lacustrine shale can store and channel oil and gas. The hybrid OM–clay–carbonate (sulfate) and the pores inside are important through the oil window. Moreover, the development of the pores depends not only on hydrocarbon generation but also on the interaction of hydrocarbons and organic acid dissolution. This finding has important significance in the accumulation of oil and gas in continental shales.〈/span〉
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  • 21
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Thermal conductivity is a major influencing factor on subsurface conductive heat transport and resulting temperature distribution, which in turn is a key parameter in basin modeling. Basin modeling studies commonly use representative literature values of thermal conductivity despite their impact on modeling results. We introduce a workflow for quantifying the effect of uncertain thermal conductivity on subsurface temperature distribution and thus on basin modeling results and test this workflow on a two-dimensional generic model from the Nordkapp Basin; a prior ensemble of possible models is conditioned according to Bayes’ theorem to incorporate prior knowledge of temperature data. This conditional probability yields a posterior ensemble of temperature fields with a significantly reduced standard deviation. To verify our approach, we use five characteristic scenarios from the posterior ensemble for transient petroleum systems modeling. How considering uncertain thermal conductivity affects variance in hydrocarbon generation is assessed by modeling corresponding vitrinite reflectances (〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉).Temperature uncertainty increases with depth. It also increases with increasing offset from the salt diapirs, which can be associated with a large lateral heat-flow component in the complex tectonic environment of the Nordkapp Basin. The introduced workflow can reduce temperature uncertainty significantly, especially in regions with high prior uncertainty. The 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 is very sensitive to changes in thermal conductivity because the onset depth of the gas window in the Nordkapp Basin may vary by up to 800 m (2600 ft) within the 95% confidence interval. This demonstrates the importance of quantification of the uncertainty in thermal conductivity on thermal basin modeling.〈/span〉
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  • 22
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Oil API gravity predictions using published basin modeling source rock (SR) reaction kinetics have displayed poor matches between modeled output and field observations because these kinetic models do not predict increasing API gravities with increasing maturity. Ideally, an SR kinetic model should use at least two liquid components of different densities, which are generated and expelled from the SR such that the API gravities are a consequence of relative mixing. Very few available kinetic models predict APIs with reasonable trends, but those are either not adjustable to calibrate to field observations or do not consider sorption, which is a necessary process when evaluating unconventional resources. Five new kinetics data sets are presented in this paper, each representing a standard SR type, which provide geologically reasonable API gravity trends and ranges. Each kinetic model uses two liquid pseudocomponents and two vapor pseudocomponents. The relative ratios between the pseudocomponents at full kerogen transformation are average ratios available from public and proprietary kinetic data sets. The primary generation follows published activation energies, including minor shifts, which allow peak generation to occur at lower activation energies for the heavier liquid pseudocomponent and at higher energies for the lighter one. This systematic shift of activation energies thus results in a constant change in API gravity as primary generation progresses. Additional in-SR sorption and secondary cracking schemes support the primary generated API gravity trends. The default ranges of API gravity for the new five kinetic models represent observed averages but can be adjusted easily.〈/span〉
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  • 23
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Shale gas in the Sichuan Basin and its periphery potentially plays an important role in the world shale gas industry. An understanding of remigration and leakage from continuous shale reservoirs is very important for shale gas exploration, especially in the Sichuan Basin and its periphery. The shale gas accumulation models that relate to remigration and leakage were developed within the Wufeng and Longmaxi black shales in the Jiaoshiba and the Youyang blocks. First, a tectono-sedimentary history of the Wufeng and Longmaxi black shales in the Sichuan Basin and its periphery was developed based on the published literature. The history exhibits a continuous distribution of high-quality Wufeng and Longmaxi black shale, which is the foundation of the shale gas formation. Second, the shale gas remigration–accumulation model in the anticlines was clarified by using data collected from the shale gas fields in Jiaoshiba block. The shale gas model for the Jiaoshiba block was developed on the basis of a continuous shale reservoir distribution, differentiated structural deformation, and a gas self-sealed system. Third, the shale gas fault failure leakage model in the fault blocks and the erosion model in the residual areas were revealed based on the shale reservoir and shale gas content heterogeneity in the Youyang block. These two models were validated by available data including 13 two-dimensional seismic lines and 2 shale gas exploration vertical wells in the Youyang block. Shale gas areas with high gas resource and gas production rates in the anticlines were defined by the remigration–accumulation model. The fault failure leakage model was used to find shale gas with limited commercial potential, whereas commercial shale gas was largely lacking according to the erosion residual model. The study on remigration and leakage from continuous shale reservoirs in the Sichuan Basin and its periphery can be used to better understand and improve the exploration efforts based on resource preservation.〈/span〉
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  • 24
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Some fault zones leak vertically to the ground surface or seafloor, whereas most others remain naturally sealed. Understanding the factors that cause this leakage is essential for predicting and preventing such leakage for both conventional reservoir development and subsurface CO〈sub〉2〈/sub〉 storage. This study, a comparison of leaking and nonleaking natural CO〈sub〉2〈/sub〉 gas accumulations, provides such constraints. We compare and contrast trap configurations, fluid pressures, and stress states for several natural CO〈sub〉2〈/sub〉 accumulations from the Colorado Plateau. Extensive surface geologic data are integrated with subsurface data from a large suite of groundwater and hydrocarbon wells. Leakage of CO〈sub〉2〈/sub〉 is documented by geochemical surveys and the occurrence of extensive travertine deposits. The leakage occurs exclusively in fault fracture damage zones where the total fluid pressure reduces the minimum horizontal effective stress to approximately zero. These results are consistent with natural and accidentally induced fault seeps from some deep-water hydrocarbon reservoirs. These criteria can be used to evaluate the potential for fault zones to provide vertical leakage pathways and loss of fluid containment.〈/span〉
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  • 25
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Fault damage zones may significantly affect subsurface fluid migration and the development of unconventional resources. Most analyses of fault damage zones are based on direct field observations, and we expand these analyses to the subsurface by investigating the damage zone structure of an approximately 32-km (∼10〈sup〉5〈/sup〉-ft)-long right-lateral strike-slip fault in Oklahoma. We used the three-dimensional (3-D) seismic attribute of coherence to first define its regional and background levels, and then we evaluated the damage zone dimensions at multiple sites. We found damage zone thickness of approximately 1600 m (∼5300 ft) at a segment that is dominated by subsidiary faults, and it is slightly thicker at a segment with a pull-apart basin. The damage zone intensity decays exponentially with distance from the fault core, in agreement with field observations and distribution of seismic events. The coherence map displays a strong asymmetry of the damage zone between the two sides of the 3-D fault, which is related to the subsidiary structures of the fault zone. We discuss the effects of heterogeneous stress field on damage zone evolution through the detected subsidiary structures. It appears that seismic coherence is an effective tool for subsurface characterization of fault damage zones.〈/span〉
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  • 26
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Using recently acquired three-dimensional seismic data, we summarize typical patterns for seismic-based identification and stage analysis of sedimentary units in the Eocene succession of the southern slope-break belts of the Bozhong sag, Bohai Bay Basin, China. The sedimentary units in the study area are characterized by progradational reflectors and mound-shaped, bidirectional downlapping reflectors in dip and strike directions, respectively. Differential characteristics of a distinct sedimentary unit within one lobe are documented. The major provenance direction is defined and characterized by the largest dip angles of reflectors, the longest transport distance of sediments, and the thickest deposits in comparison to other dip directions—all recognized in this study and serving as typical characteristics for sedimentary unit identification and separation from the overlapped sedimentary complex. This study also summarizes diverse patterns—including collateral and prograding types—of sedimentary unit contact relationships and stage analysis along dip and strike directions. Collateral patterns are composed of three subtypes: superimposed, antithetic, and isolated. Three sedimentary units—S1, S2, and S3—are recognized in the study area. Summarized patterns of sedimentary unit contact relationships indicate that S1 was deposited earliest and S3 latest. The proposed patterns supplement seismic-based sedimentologic studies. This work may serve as a useful reference for sand-body characterization and stage analysis in other basins and similar areas.〈/span〉
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  • 27
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The entire range of hydrocarbons in Bashituo oils from Devonian and Carboniferous reservoirs were investigated to determine their origin, as well as their alteration, mixing, and maturity using gas chromatography, gas chromatography–mass spectrometry, and stable carbon isotope analysis. These geochemical studies indicate that the crude oils in the Devonian and Carboniferous reservoirs share similar C〈sub〉15+〈/sub〉 molecular marker compositions of marine organic matter origin, whereas their light hydrocarbon compositions show distinct differences. The Carboniferous-reservoired oils are characterized by a relatively greater abundance of cycloalkanes and methylcyclohexane, which indicate a terrestrial organic matter (OM) contribution. Based on biomarker and carbon isotope analysis, Cambrian–Ordovician (Є-O) marine rocks are assumed to be the main source for both the Devonian- and Carboniferous-reservoired oils, whereas Carboniferous rocks with terrestrial OM input also contributed to the Carboniferous-reservoired oils. The coexistence of 25-norhopanes, evident humps from unresolved complex mixture, and intact n-alkanes in Devonian-reservoired oils indicate a mixture of early-charged biodegraded oils with late fresh oils, corresponding to at least two oil-generation episodes by the Є-O rocks. Light hydrocarbon indicators suggest a relatively high maturity beyond peak oil generation for the Є-O–sourced late fresh oil, whereas C〈sub〉15+〈/sub〉 molecular marker parameters indicate a maturity equivalent to early peak oil generation for the Є-O–sourced, early-charged biodegraded oil. The maturity of the Carboniferous-sourced oil is equivalent to peak oil generation. The application of the entire range of hydrocarbons is essential when assessing a mixed or altered oil system because light hydrocarbons and biomarkers may yield different source-oil–correlations and maturities.〈/span〉
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  • 28
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The Dibei gas field is a large tight gas field located in the Kuqa subbasin, Tarim Basin, northwestern China. The reservoir is within the Lower Jurassic Ahe Formation (J〈sub〉1〈/sub〉a) and has porosity and permeability ranges of 2%–8% and 0.01–1 md, respectively. Two episodes of hydrocarbon charge are identified based on a detailed study of fluid-inclusion petrography and microthermometry, fluorescence spectroscopy characteristics, and the thermal maturity of both gas and light oil. Low-maturity oil as represented by hydrocarbon inclusions with yellow-green fluorescence entered the reservoir circa 23–12 Ma, whereas high-maturity hydrocarbons, as indicated by hydrocarbon inclusions with blue-white fluorescence, have charged the reservoir since 5 Ma. The hydrocarbon charge process combined with porosity evolution determined the present gas–water distribution characteristics in the Dibei gas field. Porosity in the J〈sub〉1〈/sub〉a sandstone reservoir was relatively high during the first episode of hydrocarbon charge, which allowed oil to migrate upward and accumulate in structural highs under buoyancy. From 5 Ma to the present, the Dibei gas field experienced strong tectonic compression associated with intense thrust-fault reactivation, causing deformation and oil leakage from the reservoir. Continuous tight sand deposits along the slope areas, located far away from the active faults, became favorable accumulation sites for gas derived from the underlying Triassic source rocks. Hydrocarbon accumulation along the slope area in the Ahe Formation is dominantly controlled by equilibrium between hydrocarbon-generation pressure and capillary pressure.〈/span〉
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  • 29
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The Isthmian salt basin in the southern Gulf of Mexico can be divided into the Yucatán and Campeche subbasins, separated by a base-salt high near the nose of the Yucatán platform. Despite their proximity, these two subbasins experienced radically different histories in the period immediately following salt deposition.Portions of the Yucatán subbasin are characterized by large-scale (locally as much as 60 km [37 mi]) downdip translation of salt and suprasalt sediments during the Late Jurassic. This translation produced a major detached extensional province at the updip end of the basin, which is not compensated by observed shortening downdip. We interpret this history to be a result of unconfined seaward flow of salt and its cover during basin opening, a process mirrored on the conjugate Florida margin.The Campeche subbasin, in contrast, shows no evidence of significant Late Jurassic translation detached on salt. No large-scale extensional or contractional provinces of Mesozoic age are evident, although some minor translation did occur. We suggest that salt in the Campeche subbasin was confined at its seaward end, which prevented the seaward salt flow experienced in the Yucatán subbasin. Furthermore, salt at the seaward end of the Campeche subbasin lies 2–3 km (1–2 mi) above oceanic crust, in contrast to salt lying on crust whose top sits at or below the level of oceanic crust at the seaward ends of the Tamaulipas, Yucatán, and Florida margins. The Campeche subbasin thus appears to have been perched relative to other parts of the Gulf of Mexico.〈/span〉
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  • 30
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Economic accumulations of hydrocarbons in the onshore Llanos Basin of Colombia are characterized by a central zone (Casanare province) with greater than 20° API gravity oils and a southern province with biodegraded, less than 15° API gravity oils. To date, no conceptual model successfully explains this spatial zonation. In this paper, we employ multiple one-dimensional time–temperature models to map the kitchens for three different source rocks and compare maturity levels through the Cenozoic with the presence or absence of reservoir, seal, overburden, and traps in paleogeographic maps of the Llanos Basin. We find that the Llanos Basin Cenozoic petroleum migration and charge may have been governed by a sedimentary–structural evolution tied to the adjacent orogenic belt in which (1) Paleogene stratigraphic traps developed in the south, as favored by a more segmented basement and potentially transpressional stresses; (2) a subsequent Neogene phase with more pervasive east-dipping low-displacement normal fault traps was discovered; and (3) a final Pliocene–present day phase of contractional traps was found in the easternmost foothill areas. When compared with the evolution of several potential kitchens, we suggest that Upper Cretaceous rocks from the Eastern Cordillera are the primary hydrocarbon source in the zone of heavy biodegraded oils to the south, whereas Lower Cretaceous and selected terrigenous Upper Cretaceous source rocks are largely responsible for the younger Neogene contractional traps of the foothills. This evolutionary pattern for the Llanos Basin favors the presence of smaller but numerous hydrocarbon accumulations rather than the broader zones of heavy oils, as found in the Orinoco belt of Venezuela.〈/span〉
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  • 31
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Evaluating uncertainty in karst pore volume (〈span〉KPV〈/span〉) is a current industry challenge that is critical for field development planning and optimizing recovery. Hydrocarbon pore volume in karst can be significant in large super-giant fields. Although a wide variety of karst features and the geologic processes that describe their morphology have previously been described in many studies, understanding exactly how to translate this knowledge of karst into practical guidelines for the assessment of pore volume in carbonate reservoirs remains an industry challenge. In this paper, we present a robust model-assisted characterization workflow that integrates well data, seismic data (when available), drilling data, geologic concepts from modern and ancient outcrop analogs, and the application of discrete fracture network (DFN) technology to explicitly model karst features. These DFN models of karst serve as powerful visualization and communication tools in addition to quantifying the 〈span〉KPV〈/span〉. The model-assisted characterization workflow presented is specifically designed for the rapid evaluation of multiple viable geologic scenarios in recognition of the inherent uncertainty in karst morphology, fill, and sampling bias. We present nomograms to facilitate fast practical estimates of karst abundance and porosity, as well as cave area estimates from volumes lost while drilling to help condition and validate the morphometric inputs used for modeling karst. A synthetic reservoir case study with varying degrees of karst that is interpreted to be coastal in origin is used to demonstrate the workflow.〈/span〉
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  • 32
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The influence of thermal maturity on porosity in shale samples from the Upper Devonian Duvernay Formation is examined. The samples span a maturity range from immature to the wet gas window. Porosity decreases from immature to the oil window, primarily because of compaction. Relatively high porosity of wet gas window samples is ascribed to formation of secondary organic pores, feldspar dissolution pores, and primary pore preservation by the quartz framework. The final decline in the porosity of the dry gas window samples is explained by greater compaction, the disappearance of secondary organic pores, and feldspar dissolution pores.Porosity correlates positively to quartz content and negatively to carbonate content; no relationship was evident between porosity and clay or total organic carbon content. No obvious correlations exist between rock composition and permeability except that SiO〈sub〉2〈/sub〉 content shows a weakly positive correlation to permeability. Permeability is highest in immature samples, which have the greatest pore and pore-throat sizes. Nitrogen adsorption and mercury injection analysis show that pore and pore-throat sizes decrease with increasing maturity.Visible pores, imaged by scanning electron microscopy and helium ion microscopy, exist as organic pores, including bubblelike pores developed within organic matter (OM) and fissure-type pores, intraparticle pores mainly developed within carbonate grains, and interparticle pores either within a clay-rich matrix or between rigid mineral grains. In immature samples, the primary pores are interparticle pores between clay minerals and other mineral grains. The OM fissures are ubiquitous in oil window samples, and secondary bubblelike OM–hosted pores are well developed within gas window samples.〈/span〉
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  • 33
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉As a three-dimensional geological body, a fault zone has a complex internal structure. Disputes remain over flow pathways of fluids within fault zones. Well and seismic data cannot be used to effectively identify the internal structures of a fault zone. Furthermore, continuous core sampling in fault zones is commonly limited. Fewer studies of flow pathways along reverse faults are done in a sedimentary basin. Through extensive outcrop observations, sampling, and measurements in the northwestern Sichuan Basin of China, this study enhances our understanding of fluid evolution and the main pathway of vertical fluid flow along a reverse fault. In the studied carbonates, deep hot brine initially entered the fault zone and migrated upward along the fault core, then moved to shallow strata, mixed with meteoric water, and cooled in the fault zone. In the studied sandstone and shale, a paleo-oil pool formed in the fault damage zone. After that, forced by uplift and reactivation, oil migrated into the fault core along fractures and was cooled, washed, biodegraded, and oxidized by meteoric water. In the sandstone–sandstone juxtaposition faults, the oil shows are distinctly different between hanging wall and footwall. Fault rocks (sand and shale gouges) that developed along the principal slip surface seem to have prevented fluid flow across the fault. This evidence suggests that fault core and inner damaged zone are the main pathways of vertical fluid flow along the investigated reverse fault zone.〈/span〉
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  • 34
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The impact of marine incursions during transgression (i.e., sea level rises and the shoreline moves landward) on the formation and quality of lacustrine source rocks is an important and contentious issue. In this study, we present a case study of the Paleogene Hetaoyuan Formation in the Biyang sag, Nanxiang Basin, eastern China. Paleontological, trace-element, and biomarker data indicate that the Hetaoyuan source rocks in this region were influenced by a marine incursion. The paleontological evidence indicates that the marine incursion resulted in the introduction of red and brown algae, which commonly inhabit marine environments. Trace-element analyses yielded representative evidence of marine incursion (e.g., equivalent boron content 〉300 ppm and B/Ga ratio 〉4.2). Biomarker evidence for marine incursion includes C〈sub〉26〈/sub〉/C〈sub〉25〈/sub〉 tricyclic terpanes ratios of 1:3, which is the threshold for distinguishing marine organic matter from lacustrine. Using the B/Ga ratio as a typical paleosalinity indicator, it was determined that the influence of marine incursion decreased from the Biye 1 to Cheng 2 to An 3006 wells, with the B/Ga ratio average decreasing from 7.51 to 6.81 to 3.73, respectively. With an increasing extent of marine incursion (e.g., distance landward, overall water depth, and marine–freshwater mixing), the primary productivity of organic matter increased, and the preservational environment became more reducing. These changes resulted in higher contents of organic matter (total organic carbon = 2–8 wt. %) and a more favorable type of organic matter for oil generation (kerogen type I–II), indicating that the marine incursion had a positive effect on the formation of source rocks. Therefore, the formation mechanism of high-quality source rocks in coastal lacustrine basins during high sea-level periods and associated resource potential might need to be reevaluated (e.g., the Campanian lower Neslen Formation along the margins of the Western Interior Seaway of North America and the terminal Oligocene–early Miocene in the fluvial Saldanha Bay at the southwestern tip of Africa). The results also provide useful data for regional oil and gas exploration.〈/span〉
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  • 35
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉The authors of the paper “Geochemical characteristics of crude oil from a tight oil reservoir in the Lucaogou Formation, Jimusar sag, Junggar Basin” by Cao et al. (〈span〉AAPG Bulletin〈/span〉 v. 101, no. 2, 2017, p. 〈strong〉〈a href="https://pubs.geoscienceworld.org/article.aspx?volume=101&page=39"〉39–72〈span〉〈/span〉〈/a〉〈/strong〉) have informed the editor of necessary changes to this paper.〈/span〉
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  • 36
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The Vizcaino fore-arc basin accumulated approximately 4 km (∼13,000 ft) of upper Albian–middle Eocene siliciclastic marine sedimentary rocks derived from the Peninsular Ranges in Baja California. Data from eight exploratory wells document the micropaleontological content and lithological characteristics of these rocks. The strata studied represent mostly neritic–upper bathyal marine environments and overlie a basement composed of Cretaceous granitic rocks, or Aptian–Albian volcaniclastic sedimentary rocks correlative with the Alisitos Formation. We recognize four major depositional sequences within the basin that are related to the regional geology. The basal Albian–Turonian sequence 1 represents the initiation of fore-arc basin sedimentation, contains continental conglomerates that change to bathyal shales, and correlates with the lower part of the Valle Group of the Vizcaino Peninsula. Sequence 2 is Coniacian–Paleocene, includes basal conglomeratic sandstones grading into Maastrichtian bathyal shales, and usually overlies a Coniacian–Santonian unconformity. Sequence 2 is represented at the surface by the Rosario Group in northwestern Baja California and the upper part of the Valle Group in the Vizcaino Peninsula. Sequence 3 is Paleocene–middle Eocene, represents continuity of fore-arc sedimentation in neritic–upper bathyal conditions, is capped by a major unconformity, and correlates with the Sepultura and Bateque Formations to the north and south of the basin, respectively. The uppermost Miocene–Pliocene sequence 4 is composed of marine sandstone–siltstone unconformably overlying sequence 3 and is correlative with the Tortugas Formation that represents sedimentation after the end of subduction of the Farallon plate beneath the North America plate.〈/span〉
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  • 37
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Fault systems in extensional basins commonly display geometries that vary with depth, reflecting depth- and lithology-dependent mechanical strength. Using an experimental approach, we investigate this relationship by deploying physical analog models with stratified sequences consisting of brittle–ductile (sand–silicone polymer) sequences subject to single and polyphase deformation. The experiments were used as analogs for a sandstone sequence interlayered by beds of evaporates or overpressured or unconsolidated mudstone in nature (the latter being representative of decollement horizons).Experiments (series 1 [S1]) using homogeneous and stratified quartz and feldspar sand produced asymmetric, composite single grabens with diverse fault frequencies and fault styles for the graben margin faults.For the mechanically stratified experiments with one decollement level (series 2), contrasting graben configurations were produced, in that the lowermost sequence was characterized by graben geometries of similar type to that of the S1 experiments, whereas the sequence above the decollement was characterized by large fault blocks, delineated by steepened or oversteepened faults.The experiments with two decollements (series 3) were displayed similarly but included graben geometries that widened upward, with each level being characterized by independent fault systems.The results can be used to explain strata-bound fault patterns and depth-dependent extension as seen in several places along the Norwegian continental margin and elsewhere.〈/span〉
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  • 38
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉In this study, we provide new data to understand the groundwater flow patterns in the Llanos Basin and their impact on oil biodegradation and the geothermal regimes as well as how the structural styles and anthropogenic activities impact these patterns. Previous studies suggest an active flow of groundwater and variable salinities whose spatial pattern is apparently unrelated to topographically driven groundwater flow. These observations have led to different hypotheses regarding the influence of groundwater flow on Llanos Basin geothermal gradients and oil biodegradation.In this contribution, we present data regarding the hydraulic heads, salinities, geothermal gradients, and structural styles of the Llanos Basin to propose hypotheses explaining these observations. Structural cross sections and subsurface stratigraphic correlations allow us to suggest that the pattern of flow is best explained by a correlation between groundwater flow and structural styles. A basement map of the Llanos Basin confirms that the most important factor controlling geothermal gradients is the type of basement, whereas the factor of groundwater flow appears to be of secondary importance. The evolution of the basin and the frequent absence of correlation between fresh water and the more biodegraded oils support the interpretation that biodegradation is controlled by an older flow of water that started as early as the Oligocene. Finally, mass balances suggest that the temporal scales and volumes of groundwater flow are much larger than the scales observed during the development of the oil fields.〈/span〉
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  • 39
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉As a three-dimensional geological body, a fault zone has a complex internal structure. Disputes remain over flow pathways of fluids within fault zones. Well and seismic data cannot be used to effectively identify the internal structures of a fault zone. Furthermore, continuous core sampling in fault zones is commonly limited. Fewer studies of flow pathways along reverse faults are done in a sedimentary basin. Through extensive outcrop observations, sampling, and measurements in the northwestern Sichuan Basin of China, this study enhances our understanding of fluid evolution and the main pathway of vertical fluid flow along a reverse fault. In the studied carbonates, deep hot brine initially entered the fault zone and migrated upward along the fault core, then moved to shallow strata, mixed with meteoric water, and cooled in the fault zone. In the studied sandstone and shale, a paleo-oil pool formed in the fault damage zone. After that, forced by uplift and reactivation, oil migrated into the fault core along fractures and was cooled, washed, biodegraded, and oxidized by meteoric water. In the sandstone–sandstone juxtaposition faults, the oil shows are distinctly different between hanging wall and footwall. Fault rocks (sand and shale gouges) that developed along the principal slip surface seem to have prevented fluid flow across the fault. This evidence suggests that fault core and inner damaged zone are the main pathways of vertical fluid flow along the investigated reverse fault zone.〈/span〉
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  • 40
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Porosity–permeability transforms were generated using an extensive data set covering two oil-bearing formations in Ohio: the Clinton Sandstone in eastern Ohio and the Copper Ridge Dolomite in central Ohio. The reservoirs were selected because of their historical importance as oil producers and their potential as targets for CO〈sub〉2〈/sub〉 use for enhanced oil recovery and associated geological storage. The porosity-permeability transforms generated in this study have coefficients of determination that are nearly double those in the published literature. Methods applying other information (e.g., lithofacies type and reservoir depth) to improve the transforms are also discussed. Ultimately, it was determined that although subdividing the Clinton Sandstone data by geologically similar areas constrained the porosity and permeability values, the data for most areas were too limited to yield robust correlations. Thus, the range of possible outcomes should be determined using the transform derived from all available data. The Copper Ridge values were largely not constrained when subdivided by depth.〈/span〉
    Print ISSN: 1075-9565
    Electronic ISSN: 1526-0984
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  • 41
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The middle Cambrian Maryville–Basal sands in the interval of 4600–4720 ft (1402.1–1438.7 m) in the Kentucky Geological Survey 1 Hanson Aggregates well (i.e., muddy sandstones separated by sandy mudstones) were evaluated to determine effective porosity (ϕ〈sub〉〈span〉e〈/span〉〈/sub〉), clay volume (〈span〉Vc〈/span〉), and supercritical CO〈sub〉2〈/sub〉 storage capacity. Average porosity and permeability measured in core plugs were 8.71% porosity and 2.17 md permeability in the Maryville sand and 10.61% porosity and 15.79 md permeability in the Basal sand. The ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 and 〈span〉Vc〈/span〉 were calculated from the density log using a multiple-matrix shaly sand model to identify four formation lithologies: muddy sandstone, sandy mudstone, dolomitic mudstone, and dolomitic claystone. Average ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 and 〈span〉Vc〈/span〉 calculated in the Maryville sand were 8.9% and 35.3%, respectively, and an average of 8.7% and 41.2% in the Basal sand, respectively. Calculated ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 exhibits a good match with porosity measured in core plugs. Prior to step-rate testing, static reservoir pressure was 2020 psi (13.9 MPa), representing a 0.435 psi/ft (9.8 kPa/m) hydrostatic gradient, which is consistent with other underpressured reservoirs in Kentucky. The interval fractured at 2698 psi (18.0 MPa), yielding a fracture gradient of 0.581 psi/ft (12.7 kPa/m). Pressure falloff analysis suggests a dual-porosity/dual-permeability reservoir consistent with core data. Estimated 50th percentile supercritical CO〈sub〉2〈/sub〉 storage volume supercritical CO〈sub〉2〈/sub〉 storage volume, using 7% porosity cutoff for determining net reservoir volume, is 0.538 tons/ac (1.33 t/ha). Thin reservoir sands, low porosity and permeability, and low fracture gradient, however, preclude the Maryville–Basal sands as large-volume deep-saline CO〈sub〉2〈/sub〉 storage reservoirs in this area.〈/span〉
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  • 42
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Petroleum mobility in shale is closely correlated with the attributes of shale petroleum and pores; however, the relationship between these attributes is poorly understood. To characterize petroleum mobility in self-sourcing reservoirs, a suite of mature Eocene shales was selected and subjected to organic solvent extraction, and both the raw and solvent-treated samples were analyzed using pyrolysis, nitrogen adsorption, and x-ray diffraction. The results show that the pore surface area and pore volume of these shales are mainly controlled by their clay and quartz content rather than their organic matter (OM) content and are limited by the presence of carbonates. Correlations of soluble OM with pore surface area and volume after solvent extraction indicate that petroleum mobility of studied shales is initiated when the petroleum content reaches 0.70 wt. % of the rock and the pore diameter is over 12.1 nm. These thresholds are established in the studied area and should be similar for the self-sourcing reservoirs from similar sedimentary environments. This work proposes a method to reveal the thresholds of petroleum content and pore diameter for petroleum mobility in self-sourcing reservoirs, which is useful in the assessment of petroleum producibility and is of significance for unconventional petroleum exploration and exploitation.〈/span〉
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  • 43
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Miocene carbonate reservoirs in Central Luconia, offshore Sarawak, Malaysia, have been delivering gas for over 30 yr. In this paper, learnings from that period of production are used to understand the key drivers affecting flow during production and recovery optimization in existing fields as well as development decisions for new discoveries. The large data set, generated over more than 40 yr, was analyzed in a consistent manner through a holistic database, constrained by a stratigraphic framework, to allow reservoir units to be compared like-for-like (“integrated knowledge base” [IKB] concept). Carbonate reservoir heterogeneities impacting flow are grouped into “horizontal–heterogeneities”—argillaceous flooding layers and exposure-related karst—and “vertical–heterogeneities”—large-scale architectural elements, found especially along platform margins. Both types of heterogeneities control water ingress during production and influence the recovery mechanism. Argillaceous flooding layers can act as baffles, holding back water rise during production, or can form pressure compartments. Long-lived, fault-bounded reef margins, carbonate shoals, islands, and karsts can be vertical conduits for aquifer inflow. Platform shape and architecture impact column height and hence recovery efficiency. Additional drivers impacting recovery were found to be gas-column height, aquifer size and permeability, pressure connection to neighboring fields, and field development concepts. All drivers identified impact decisions throughout the field life, e.g., well count and design, intervention capabilities, evaluation and mitigation of early-water breakthrough, reservoir management, selecting enhanced recovery methods, and abandonment pressure. The IKB allowed to derive “big rules” on what matters for flow, which were used to decide on development strategies for greenfields in Central Luconia. The presented outcomes can be extrapolated to comparable carbonate systems, whereas the IKB approach can be adapted and applied to other mature basins and reservoir types where equally vast and historic data sets are awaiting to be used in the current era of digitalization.〈/span〉
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  • 44
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉For oil-rich shales, current solvent extraction– and thermal extraction–based methods inaccurately measure hydrocarbon-filled porosity (〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉). Moreover, the hydrocarbon composition is not characterized by either method. Here, we show how open-system programmed thermal extraction and pyrolysis, LECO total organic carbon, Archimedes bulk density, and helium pycnometry measurements are integrated to calculate oil and gas pore volumes, characterize their composition, and estimate mobility. Use of a modified multiramp, slow-heating thermal extract, and pyrolysis temperature program further subdivides the 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉. Saturate–aromatic–resin–asphaltene (SARA) separation and gas chromatography of solvent-extracted organic matter and thermally extracted oils are used to compositionally classify the 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉. The segregated bulk compositions of gas- and oil-filled porosity measured via this method are shown to overlap and are broken into the following categories: gas-filled porosity (∼C〈sub〉1〈/sub〉–C〈sub〉14〈/sub〉), light oil–filled porosity (∼C〈sub〉6〈/sub〉–C〈sub〉36〈/sub〉), and heavy oil–filled porosity (∼C〈sub〉32〈/sub〉–C〈sub〉36〈/sub〉+). Furthermore, slow-heating multiramp thermal extraction can subdivide the light oil–filled porosity into four components capturing the C〈sub〉11〈/sub〉–C〈sub〉13〈/sub〉, C〈sub〉12〈/sub〉–C〈sub〉16〈/sub〉, C〈sub〉14〈/sub〉–C〈sub〉20〈/sub〉, and C〈sub〉17〈/sub〉–C〈sub〉36〈/sub〉 ranges of the extractable organic matter. Analysis of solvent-extracted oils by SARA identifies abundant saturates and aromatics in the light oil–filled porosity and abundant resins and asphaltenes in the heavy oil–filled porosity. Low-maturity shales can be dominated by heavy (C〈sub〉32〈/sub〉+) oils rich in asphaltene and resin fractions not observed in the produced fluid. The ratios of SARA components in the C〈sub〉15〈/sub〉+ fraction of produced fluid and core extract can be used to better estimate the potentially mobile 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉.〈/span〉
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  • 45
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The upper zone of the Lower Cretaceous Kharaib Formation (151–177 ft [46–54 m] thick in the studied wells) is a major oil reservoir in several giant oil fields. Wide variations in porosity and permeability of this zone have been shown to result from both the inhibition of burial cementation by oil in the crest of each field and localized cementation adjacent to stylolites, combined with the more subtle influence of widely varying depositional mud content and grain size. The present study examines these relationships in closer detail, using core and petrographic observations from two wells on the oil-filled crest and two wells on the water-filled flanks of a giant domal oil field.Although porosities are higher overall in the crestal cores, each well shows wide variations within each of seven main groupings of the samples by depositional texture. This heterogeneity results mainly from the distribution of clay, which is concentrated along depositional laminations and causes widely varying porosity losses in all textures by promoting stylolite development and associated calcite cementation. Higher clay abundance (and lower porosity) within the upper and lower 12–17 ft (4–5 m) of the reservoir reflects increased influx of siliciclastic fines across the epeiric Barremian carbonate platform immediately following and preceding, respectively, third-order falls in global sea level. Most (95%) of porosity-permeability data from the studied wells lie within Lucia rock-fabric class 3, showing distinct but relatively subtle differences between texture groups, whereas a subordinate part of the data from the upper, relatively mud-poor third of the reservoir plot at higher permeabilities. Development of a predictive model for the petrophysical heterogeneity of this example requires a combination of the following: (1) a diagenetic model for porosity controls; (2) the use of a modestly higher porosity-permeability transform (upper class 3) in the upper part of the reservoir than in the lower reservoir (lower class 3); and (3) a recognition of the scattered and widely varying occurrences of exceptionally high permeabilities in the upper reservoir.〈/span〉
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  • 46
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Porosity is one of the most important rock properties in describing hydrocarbon reservoirs. Tests on core samples provide direct and representative porosity data, and the measurement of porosity at high confining pressures is recognized to correlate well with subsurface reservoir porosity. Whereas theoretical deductions of the changes and relationships of pressures, volumes, and compressibility suggest that porosity is reduced during the coring and lifting processes, the porosity measurement at elevated confining pressure does not evaluate original reservoir porosity. This theory is quantitatively validated by repeated laboratory experiments of loading and unloading on sandstone core samples. When the in situ confining pressure is approximately 30–35 MPa (∼4350–5076 psi), coring and lifting would cause a porosity reduction of approximately 1.2%–1.6%, and the porosity test under high confining stress results in further porosity loss. A revised approach in calculating reservoir porosity from cored samples is proposed and can have significant implications for reserve calculations, recovery factors, and geostatistical reservoir models. The study is important for both conventional and unconventional reservoirs because it discusses a fundamental mechanism of porosity change.〈/span〉
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  • 47
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉In this paper, high-resolution three-dimensional seismic data are used to interpret a transpressional salt tectonic structure in the Yingxiongling area, Qaidam Basin, China. The geometries of the salt structure and the Shizigou fault system that intersects it are precisely depicted. The Shizigou fault system is composed of suprasalt and subsalt components. The suprasalt component is a Y-shaped reverse fault, and the subsalt component is a complex flower structure. In previous studies, suprasalt and subsalt components were interpreted as two independent fault systems. This paper proposes instead that the suprasalt and subsalt faults are kinematically related and decoupled across the salt layer.〈/span〉
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  • 48
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The Canning Basin is a largely unexposed and underexplored frontier basin, formed mostly in the Paleozoic. Geological knowledge of this basin is based predominantly on sparse regional “vintage” two-dimensional seismic and small three-dimensional (3-D) seismic surveys and less than 230 exploration wells. Following seismic interpretation, an integrated interpretation was completed on airborne gravity gradiometer (AGG), magnetic, seismic, well, and complementary data along the southwestern margin of the Fitzroy trough and Gregory subbasin. Seismic data were reinterpreted using AGG data to produce a better constrained geological model. A basement structure map, two intrasedimentary structure maps, and a formation distribution map were produced. The interpretation of seismic profiles, validated through 2.5-dimensional gravity gradiometer modeling, is essential to this workflow.Repeatedly reactivated west–northwest and northwest structural trends, inherited from Proterozoic orogenies, respectively delineate the Fitzroy trough and the Gregory subbasin with its northwestern structural extension into the Fitzroy trough, the Gregory subbasin trend. Subsidence occurred during two periods of extension. An asymmetric extensional system of the Fitzroy trough controlled Ordovician–Silurian deposition of the Carribuddy Group. Devonian–Carboniferous subsidence defines the Gregory subbasin trend. This Pillara extension reactivated structures in the east of the Fitzroy trough. Simultaneous activity of both extensional fault systems and growth faulting controlled the facies and thickness distribution of carbonates and clastics of the early Carboniferous Fairfield Group. The Meda and Fitzroy transpressional phases inverted faults of the Gregory subbasin trend and Fitzroy trough, producing prospects by structural interference.The improved understanding of tectono-stratigraphic relationships, including the 3-D distribution of carbonate reservoirs, benefited the planning of seismic surveys, prospect evaluation, drilling, and acreage relinquishment.〈/span〉
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  • 49
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉In the Paleocene to Eocene Wilcox Group in the northern Gulf of Mexico, exploration targets are reaching into deep to ultradeep burial depths. At these great depths, reservoir quality (porosity and permeability) becomes an important risk factor in determining the chance of encountering an economic reservoir. Major controls on reservoir quality are pore types and abundances, pore-throat sizes, and pore network composition. These factors can be analyzed by integrating petrographic, core plug porosity and permeability, and mercury injection capillary pressure (MICP) analyses. The Wilcox sandstones are mostly lithic arkoses and feldspathic litharenites that contain primary interparticle pores, secondary dissolution pores, and micropores. However, these pore types evolve with depth and temperature. As temperature increases, the relative abundance of primary interparticle pores decreases, whereas the relative abundance of secondary dissolution pores and nano- to micropores increases. Associated with this evolution of pore networks with increasing temperature, there is a decrease in reservoir quality. This decrease in reservoir quality is caused by a transition to finer pore-throat sizes that correspond to changes in pore types. Petrographic analysis provides information on pore types, core plug porosity and permeability analysis provides information on volume of pores and effectiveness of flow, and MICP analysis provides information on pore-throat radius distribution. Through forecasting the pore network in the target temperature zone, a realistic porosity versus permeability transform can be selected to estimate permeability from wire-line log porosity.〈/span〉
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  • 50
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The Fuling gas field in Sichuan Basin, China, has produced greater than 1.5 × 10〈sup〉10〈/sup〉 m〈sup〉3〈/sup〉 (0.53 tcf) of natural gas from overmature Upper Ordovician Wufeng and lower Silurian Longmaxi shales. To systemically investigate the characteristics of wettability and connectivity and to understand the underlying causes of production behavior, we study five samples of Wufeng and Longmaxi shales with different total organic carbon contents and mineral compositions. Complementary approaches include mercury intrusion capillary pressure (MICP), contact angle measurement, spontaneous imbibition and saturated diffusion, and tracer (both nonsorbing and sorbing) migration mapped via laser ablation inductively coupled plasma mass spectrometry. According to measured contact angles and imbibition tests conducted on aqueous (deionized water and brine) and oleic (n-decane) phases, Wufeng and Longmaxi shales are strongly oil wet and moderately strong water wet. The lower boundary of estimated permeability obtained from n-decane imbibition can reach 137 nd, which is higher than the geometric mean permeability derived from the MICP method (5.5–68.8 nd). Effective diffusion coefficients of the Wufeng and Longmaxi shales are in the range of 10〈sup〉−13〈/sup〉 m〈sup〉2〈/sup〉/s (1.1 × 10〈sup〉−12〈/sup〉 ft〈sup〉2〈/sup〉/s). Tests of imbibition and saturated diffusion using tracer-containing brine show that concentrations of nanometer-sized tracers decrease rapidly (a factor of 〉10) over a migration distance of a few millimeters from the sample edge, suggesting the presence of poorly edge-connected water-wet pores. Sparsely connected hydrophilic pores, mixed wettability, and highly restricted pathways collectively contribute to the limited migration of nano-sized tracers, which probably results in the production behavior of initial steep decline and low overall recovery in the Fuling gas field.〈/span〉
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  • 51
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Recent oil discoveries in an Aptian–Cenomanian clinothem in Arctic Alaska demonstrate the potential for hundred-million- to billion-barrel oil accumulations in Nanushuk Formation topsets and Torok Formation foresets–bottomsets. Oil-prone source rocks and the clinothem are draped across the Barrow arch, a structural hinge between the Colville foreland basin and Beaufort Sea rifted margin. Stratigraphic traps lie in a favorable thermal maturity domain along multiple migration pathways across more than 30,000 km〈sup〉2〈/sup〉 (10,000 mi〈sup〉2〈/sup〉). Sediment from the Chukotkan orogen (Russia) filled the western Colville basin and spilled over the Beaufort rift shoulder, forming east- and north-facing shelf margins. Progradational shelf margin trajectories change abruptly to “sawtooth” trajectories at midclinothem, the result of reduction in sediment influx. Two stratigraphic trap types are inferred in Nanushuk basal topsets in the eastern part of the clinothem: (1) lowstand systems tracts, inferred to reflect forced regression, include a narrow, thick progradational stacking pattern perched on a sequence boundary on the upper slope; and (2) highstand-progradational systems tracts include a broad, thin wedge of shingled parasequences above a toplap surface. Both include stratigraphically isolated sandstone sealed by mudstone. Trap geometries in Torok foreset and bottomset facies in the same area include basin-floor fan, slope-apron, and slope-channel deposits that pinch out upslope and are sealed by mudstone. Significant potential exists for the discovery of additional oil accumulations in these stratigraphic trap types in the eastern part of the clinothem. Less potential may exist in the western part because reservoir–seal pairs may not be well developed.〈/span〉
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  • 52
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The Węglówka oil field is located in the outer Carpathians. The outer Carpathians are a region where hydrocarbons were discovered and exploited at the end of the nineteenth century in several dozen oil fields, which are relatively small. The Węglówka oil field is one of the largest in this region. In the 150 yr or so of hydrocarbon exploration in the area, more than 1 million t (〉1,237,000 tons [〉8,841,000 bbl]) of oil have been produced. Hydrocarbons are concentrated in Lower Cretaceous sandstones (Grodziszcze and Lgota sandstones) that form an anticline sealed by Upper Cretaceous marls called the Węglówka marls. These cap rocks are up to 600 m (2000 ft) thick. Because of the thrust-related exhumation, they were exposed at the surface and represent the youngest deposits in the region. The present work is focused on a detailed petrographic characterization of the Węglówka marls. This study allows petroleum geologists to better understand the evolution of porosity in these cap rocks and can serve as a foundation for the prediction of their sealing properties. The marls appear as a succession of interbedded red and green varieties, which occur in up to 2-m (6-ft)-thick beds. These beds are nonarenaceous, soft, and bioturbated. Grain size corresponds to approximately 80% clay and less than 20% silt fractions. X-ray diffraction (XRD) reveals that the marls contain, on average, 54% clay, 28% calcite, 16% quartz, up to 3% feldspars and, in red marls, 3% hematite. The XRD patterns of clay are typical of mixed-layer illite–smectite ([I–S]; 40% illite in I–S). The clay structures are dioctahedral with similar octahedral Mg and relatively high Fe〈sup〉3〈/sup〉〈sup〉+〈/sup〉 contents both in the red and green intervals. As revealed by standard petrography combined with high-resolution petrography performed through the use of a field emission scanning electron microscope, the marls have mudstone textures according to Dunham’s (1962) classification and are mostly composed of coccoliths and clay with rare nanoquartz. This rock may be considered an impure chalk. Sealing properties of the Węglówka marls are indicated by the specific surface area, porosity, pore size, and permeability, calculated using N〈sub〉2〈/sub〉 gas adsorption, helium, and mercury porosimetry. The sealing potential is postulated to result from a combination of the following: (1) origin of components (i.e., deposition of minute calcareous bioclasts and volcanic material as a source for clay); (2) oxygenated sedimentary environment (as a result of the presence of oxygen in the sediments, burrowing caused the rocks to be homogenized); and (3) tectonic-induced clogging of pore space because of reorganization of clay flakes (the rocks were strongly tectonically deformed, which resulted in reduction of porosity in clay aggregates).〈/span〉
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  • 53
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Increased oil and gas production in many areas has led to concerns over the effects these activities may be having on nearby groundwater quality. In this study, we determine the lateral and vertical extent of groundwater with less than 10,000 mg/L total dissolved solids near the Lost Hills–Belridge oil fields in northwestern Kern County, California, and document evidence of impacts by produced water disposal within the Tulare aquifer and overlying alluvium, the primary protected aquifers in the area.The depth at which groundwater salinity surpasses 10,000 mg/L ranges from 150 m (500 ft) in the northwestern part of the study area to 490–550 m (1600–1800 ft) in the south and east, respectively, as determined by geophysical log analysis and lab analysis of produced water samples. Comparison of logs from replacement wells with logs from their older counterparts shows relatively higher-resistivity intervals representing the vadose zone or fresher groundwater being replaced by intervals with much lower resistivity because of infiltration of brines from surface disposal ponds and injection of brines into disposal wells. The effect of the surface ponds is confined to the alluvial aquifer—the underlying Tulare aquifer is largely protected by a regional clay layer at the base of the alluvium. Sand layers affected by injection of produced waters in nearby disposal wells commonly exhibit log resistivity profiles that change from high resistivity in their upper parts to low resistivity near the base because of stratification by gravity segregation of the denser brines within each affected sand. The effects of produced water injection are mainly evident within the Tulare Formation and can be noted as far as 550 m (1800 ft) from the main group of disposal wells located along the east flank of South Belridge.〈/span〉
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  • 54
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Instead of using discrete values for properties that influence the volumetric calculation for recoverable reserves from the Middle Bakken, Pronghorn, and Three Forks reservoir rocks in the Williston Basin in North Dakota, an uncertainty-based assessment method was used. Various estimates have been published in the past that attempt to quantify recoverable reserves from the Bakken petroleum system. The Bakken–Three Forks trend is regarded as an unconventional tight oil play typical of a continuous-type basin-centered accumulation. However, production data reveal that areas are unequal and that certain regions stand out as sweet spots whereas others exhibit fairly high water cuts. This paper is based on 28 well models, which have been porosity-calibrated and adjusted for the prevalent thermal regime. The area of interest was delineated by geological parameters such as shale maturity and reservoir rock presence as well as existing production data. The purpose of this study is to use an uncertainty assessment method based on hundreds of basin model simulations that sample ranges of probable input parameters to quantify the recoverable reserves from the Bakken petroleum system in North Dakota. The results are displayed in reverse cumulative probability plots, tornado sensitivity charts, as well as in maps of the 10% chance, 50% chance (P50), 90% chance values. This means that there is an X% chance of success or an X probablity of realizing a certain amount of hydrocarbon. The P50 results of the uncertainty assessment indicate that approximately 4 billion bbl of oil and 3.6 tcf (102 billion m〈sup〉3〈/sup〉) of gas are recoverable from the Middle Bakken, Pronghorn, and Three Forks reservoir rocks in North Dakota. The Bakken–Three Forks trend appears to be an overcharged petroleum system, where the available pore space in reservoir rocks is the limiting factor for each accumulation.〈/span〉
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  • 55
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉In the last 30 yr, basin and petroleum system modeling (BPSM) has evolved into a large and diverse field encompassing a broad range of scientific disciplines. As BPSM is applied to an increasingly wide range of problems, what are, or should be, the future directions in the evolution of BPSM comes into question.To address this question, a survey was conducted at the AAPG Hedberg Research Conference on “The Future of Basin and Petroleum Systems Modeling,” held in Santa Barbara, California, April 3–8, 2016. To capture the full range of thoughts, participants were asked to list in priority order what they think are the three most important future directions in BPSM. The responses were collated into six general categories for analysis. The categorization process involved some qualitative judgements because some areas spanned several of the general areas.The results show that the most frequently cited directions are related to BPSM workflows, organizations, and processes. This category includes how modelers are used in an organization, how projects are executed, and how the results are interpreted and integrated.Migration modeling (primary and secondary) is the most frequently cited technical need. The results indicate that migration processes are not well understood and there are still substantial differences of thought about the processes involved and the best ways to model them.Some subjects, such as uncertainty and unconventionals, were mentioned in several of the general categories, whereas other subjects, such as increased functionality in the models, were only seldom mentioned.〈/span〉
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  • 56
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The Fengcheng Formation is a nonmarine, carbonate-dominated succession that formed under arid climatic conditions in a hydrologically closed basin. Two transects and two seismic profiles were examined, the characteristics and environmental significance of different lithofacies were studied, and a model of depositional environment divisions was proposed. The sedimentary model involved an alkaline lake in which the depositional environments consisted of a shallow saline lake margin, slope, saline lake center, and steep lake margin from northeast to southwest. The perennial central salty lake was located in the southwestern part of the study area, whereas there were widespread, low-gradient lake margins in the northeast, east, southeast, and southern parts of the study area. Lake-level fluctuations had a major influence on the shallow saline lake system and complicated the depositional environments in these areas. The deposits are derived from bedrock reworking, volcanic eruptions, and authigenic minerals that precipitated from brine during the hypersaline phase. Fine-grained terrigenous clastic sediments, volcanic ashes and dusts, and authigenic minerals mixed in the depocenter (concentration center of the brine pool), which was covered by high-salinity brines, and the depositional environment was anoxic as a result of salinity-based brine stratification. A thick sodium carbonate succession occurred in the depocenter of the ancient Mahu lake, where bedded sodium carbonate alternated with fine-grained, organic-rich tuff or tuffaceous hydrocarbon source rocks. Microorganisms bloomed in the alkaline, high-salinity brine, and the organic matter was well preserved, which is similar to those modern alkaline saline lakes in eastern Africa and western North America. Thus, the Permian Fengcheng Formation contains source rocks that formed in an alkaline saline lake.〈/span〉
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  • 57
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉After three decades of research and hydrocarbon exploration in the Nordkapp Basin (Norwegian Barents Sea), the dynamics of Mesozoic salt mobilization is still poorly understood. Both progradational loading and basement-involved extension have been proposed as triggers of salt mobilization, where the latter is most accepted. This study combines two-dimensional and three-dimensional seismic reflection data, borehole data, isochore maps, and structural restorations to (1) provide a tectonostratigraphic evolution of the Nordkapp Basin, (2) indicate which triggering mechanisms fit the observed structural styles, and (3) determine the geological controls that influenced the along-strike distribution of salt structures in the basin. Our results indicate that a combination of Early–Middle Triassic thick-skinned extension and sediment loading induced the differential loading and mobilization of the underlying salt, generating a series of northwest-shifting minibasins bounded by salt walls, ridges, and stocks. Sediment loading and the distribution of salt structures were strongly conditioned by rheology variations within the salt layer and subsalt fault activity, which (1) created tectonically induced depressions that became preferential areas of infill and differential loading; (2) caused faulting and extension of the overburden, allowing the preferential growth of reactive diapirs, which later on evolved into passive diapirs; and (3) acted as effective barriers of salt expulsion, enhancing salt inflation and growth of salt above the subsalt faults. Early Triassic differential loading occurred diachronically along strike, causing early passive diapirism, salt welding, and salt depletion in the eastern and central subbasins because of the diachronous subsalt activity and the closer proximity of these basins with respect to the sediment source, the Uralides. Although most of the salt was depleted by the end of the Middle Triassic, the ongoing extension created across-fault thickness variations and sagging of some of the west-northwest–east-southeast salt walls in the central subbasin. The rest of the structures in the Nordkapp Basin continued growing until the end of the Mesozoic by minor evacuation of the remaining salt and thin-skinned gliding and subsequent shortening triggered by subsalt fault activity. Finally, salt structures were rejuvenated and eroded during Cenozoic contraction and uplift. These results have implications for the four-dimensional understanding of the Nordkapp Basin and its petroleum system, and they can be used as an analog to decipher other confined salt-bearing basins alike.〈/span〉
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  • 58
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Oil mixing and absence of source-rock samples make it difficult to identify the hydrocarbon migration routes in a petroleum system. We provide a case study in the northwestern Junggar Basin to show that combined geochemical and phase fractionation analyses are robust tools to unravel the complex hydrocarbon migration processes. The study rebuilds a migration history that multiple-sourced hydrocarbons migrated, mixed, accumulated, and fractionated along the evolution of regional tectonics. In detail, the Shawan and Mahu sags expelled the early-stage hydrocarbons during the Late Triassic and Late Jurassic, respectively, because of their variable subsidence. These hydrocarbons charged the entire area based on the evidence from bitumen and oil inclusions. During the Early Cretaceous, both sags subsided rapidly and expelled their late-stage hydrocarbons. These hydrocarbons first mixed along unconformities in the sags, which generated mixed-source oils and induced gas washing. Subsequently, they further mixed with or displaced the encountered early-stage oils during migration along the basal unconformity of the upper Permian into the area, causing a horizontal distribution of oil maturity zones. In addition, gases flowing through the early-stage oils induced gas washing again, creating heavy oils, condensate oils, and mixed gases. After the late-stage oils finally accumulated in fractured volcanics, migration fractionation caused the remigration of light-end compositions. This study also shows the strong control of structures on hydrocarbon migration: the unconformity network provided opportunities for long-distance migration and widespread mixing of multiple-sourced hydrocarbons, whereas the paleoridge line of the Zhongguai high defined the boundary of regional migration.〈/span〉
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  • 59
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The subsurface of the highly productive Murzuq Basin in southwest Libya remains poorly understood. As a consequence, a need exists for detailed sedimentological studies of both the oil-prone Mamuniyat Formation and Hawaz Formation reservoirs in this area. Of particular interest in this case is the Middle Ordovician Hawaz Formation, interpreted as an excellent example of a “nonactualistic,” tidally influenced clastic reservoir that appears to extend hundreds of kilometers across much of the North African or Saharan craton. The Hawaz Formation comprises 15 characteristic lithofacies grouped into 7 correlatable facies associations distributed in broad and laterally extensive facies belts deposited in a shallow marine, intertidal to subtidal environment. Three main depositional sequences and their respective systems tracts have also been identified. On this basis, a genetic-based stratigraphic zonation scheme has been proposed as a tool to improve subsurface management of this reservoir unit. A nonactualistic sedimentary model is proposed in this work with new ideas presented for marginal to shallow marine depositional environments during the Middle Ordovician in the northern margin of Gondwana.〈/span〉
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  • 60
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉A large number of small-scale lacustrine sedimentary basins are widely distributed across China. Studies of such basins have been limited. These basins have complex characteristics and thus exhibit significant differences in terms of their hydrocarbon potential. At present, among the known 348 small-scale basins with areas less than 20,000 km〈sup〉2〈/sup〉 (〈7700 mi〈sup〉2〈/sup〉), 13 commercial petroliferous lacustrine basins have been identified. Of these, some are referred to as “small but enriched” because they have hydrocarbon abundances per unit area that are far higher than large- to medium-sized petroliferous basins. Small-scale petroliferous basins can be divided into the following two types based on their characteristics and causes for their small size: remnant and proto–small-scale basins. Remnant basins are sedimentary basins retained from predecessor large basins that were far larger than 20,000 km〈sup〉2〈/sup〉 (7700 mi〈sup〉2〈/sup〉) and have undergone later modification because of tectonic deformation and erosion; it is conspicuous that later modifications caused their small size. Examples of remnant basins include the Jiuxi, Jiudong, Yanqi, and Santanghu Basins. Proto–small-scale basins are small basins during their entire evolutionary history, and either they did not experience later modifications or the old basin was a small-scale basin before modification and it was their dynamics that caused their small size. According to differences in their formation dynamics responsible for their small size, the proto–small-scale basin can be divided into two subtypes: thermal basins and strike-slip basins. The thermal basin formation and evolution are reflective of a deep thermal origin; that is, there is direct or indirect evidence for existing asthenospheric upwelling that led to basin formation, and examples of thermal basins include the Nanxiang and Jinggu Basins. Strike-slip basin formation was closely related to activity on large strike-slip fault systems, and examples of strike-slip basins include the Yitong, Baise, Sanshui, Baoshan, Luliang, Qujing, and Lunpola Basins.For these small-scale lacustrine basins, the most important fact contributing to the formation of hydrocarbons and reservoirs is that these basins allowed for the deposition, preservation, and maturation of high-quality hydrocarbon source rocks. Furthermore, three common key factors that significantly affected the hydrocarbon occurrence within small-scale sedimentary basins are as follows: (1) a later modification process that benefits the preservation and maturation of the high-quality source rocks (i.e., the uplift and erosion without the destruction of main source rocks followed by basin subsidence), (2) a high geothermal background characterized by high geothermal gradient and hydrothermal activity, and (3) an elevated deep-lake sedimentation rate (〉200 m/m.y. [〉656 ft/m.y.]) during deposition of the source rocks within underfilled and balanced-filled lakes.〈/span〉
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  • 61
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The Yinggehai–Song Hong Basin has received a large amount of terrigenous sediment from different continental blocks since the Paleogene. The Yingdong slope, which is located on the eastern side of this basin, is an important potential gas province, but the provenance of the marine sediments in this area are poorly understood. The detrital zircon U-Pb geochronology of sedimentary rocks from the lower Miocene to Quaternary is examined in this study to investigate the temporal and spatial variations in provenance since the early Miocene. The U-Pb ages of detrital zircon range from 3078 to 30 Ma, suggesting that sediment input is derived from multiple sources. Detailed analyses of these components indicate that both the Red River and Hainan are likely the major sources of the sediments on the Yingdong slope, with additional minor contributions from central Vietnam (eastern Indochina block) and possibly the Songpan–Garze block. Variations in the dominant detrital zircon populations within stratigraphic successions display an increasing contribution from the Red River since the middle Miocene. This resulted from the progradation of the Red River Delta in the northern basin and may have also been influenced by regional surface uplift and associated climate changes in East Asia. This study shows that the Red River has had a relatively stable provenance since at least the early Miocene, indicating that any large-scale drainage capture of the Red River should have occurred before circa 23 Ma.〈/span〉
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  • 62
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The detailed depositional systems and basin evolution of Lower Cretaceous coal-bearing strata in the Erlian Basin of northeastern China were analyzed based on extensive borehole and outcrop data. A total of 7 facies associations are interpreted and consist of 14 distinct lithofacies, with lithologies including conglomerates, sandstones, siltstones, mudstones, shales, and coals. Five third-order sequences were recognized, and their internal lowstand, transgressive, and highstand systems tracts were defined based on six key sequence stratigraphic boundaries. These boundaries were represented by regional unconformities, basal erosional surfaces of incised valley fills, interfluvial paleosols, and abrupt depositional facies-reversal surfaces. Sequences I–V correspond to the rift-initiation stage, the early-rift climax stage, the late-rift climax stage, the immediate postrift stage, and the late postrift stage of the basin, respectively. The preferred sites for coal accumulation were braided fluvial delta plain, meandering fluvial delta plain, and littoral–shallow lake environments. The major coal seams formed during the early and late transgressive systems tract of sequences III, IV, and V, which were well developed in the eastern, northeastern, and northeastern parts of the Erlian Basin, respectively. Three coal depositional models were summarized in the sequence stratigraphic framework, including types 1, 2, and 3, corresponding to the Newark type, Newark–Richmond type, and Richmond type, respectively. These coal depositional models were closely related to the basin evolution. These results could provide preferred depositional environments and favorable areas of coal and coalbed methane (CBM) for the exploration and development of coal and CBM in the Erlian Basin, with the Jiergalangtu, Huolinhe, Baiyinhua, and A’nan sags recommended as the key sags.〈/span〉
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  • 63
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Giant petroleum accumulations worldwide with burial depths more than 7000 m (〉23,000 ft) occur mostly in Mesozoic and Cenozoic reservoirs and yield predominantly natural gas. Recently, however, a giant oil accumulation with reservoir depths between 7000 m (23,000 ft) and 8000 m (26,000 ft) was discovered in the lower Paleozoic section in the southern part of the Halahatang region in the Tarim Basin, China. Petroleum sourced from lower Paleozoic rocks is contained in Ordovician karst fracture-cave reservoirs and sealed by Middle–Upper Ordovician limestones and mudstones. The newly discovered superdeep accumulation is among the deepest black single-phase oil accumulations worldwide and opens up new avenues for petroleum exploration in deep-marine carbonate reservoirs. Reservoir pressures are between 75 MPa (10,878 psi) and 85 MPa (12,328 psi), with pressure coefficients between 1.2 and 1.7 and temperatures ranging between 140°C (284°F) and 172°C (342°F). Charging and accumulation of petroleum occurred during the late Hercynian orogeny, followed by subsequent gradual deep burial, which took place before rapid subsidence beginning circa 5 Ma. Following subsidence, the thickness of overlying strata increased by more than 2000 m (〉6600 ft) before finally attaining current depth. Therefore, this oil accumulation represents a well-preserved ancient petroleum system. Based on the geochemical features of oils and gases, the crude oils can be classified as mature, sourced from mixed marine organofacies of shale, marl, and carbonate, whereas the gases were cogenerated with oils. Despite very high present-day reservoir temperatures, no oil cracking has occurred because of the relatively short exposure of oils to high temperatures in a low geothermal gradient regime. Thus, there is significant exploration potential under similar conditions for liquid petroleum in superdeep strata. Faults and reservoirs are major factors controlling petroleum accumulation. Interlayer karsts with excellent fracture-cavity connectivity developed adjacent to faults, generally resulting in the enrichment of oil and gas along fault zones. High-quality reservoirs in this area are easy to identify because they exhibit strong bead-like amplitude features in seismic sections. Wells located near faults produce relatively large amounts of oil and gas. Effective karst fracture-cave reservoirs with noncracked oil may exist below 8000 m (26,000 ft) in the Tarim Basin and represent a significant exploration target in China.〈/span〉
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  • 64
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The Jurassic black mudstone and coal beds in the central Junggar Basin, northwestern China, are the major source rocks for the basin with type II〈sub〉2〈/sub〉 and type III (gas-prone) kerogens. Widespread overpressures are developed in the Jurassic stratigraphic interval. Sonic and resistivity logs display strong characteristic responses of overpressure in the mudstones, with anomalously high acoustic traveltimes and low resistivity compared with the normally pressured mudstones. The overpressured Jurassic sediment sequences appear to have undergone normal compaction because the mudstones exhibit no anomalously low bulk density. The overpressured mudstones deviate from the normally pressured mudstones in density–effective vertical stress space. The overpressure in the Jurassic source rocks is, therefore, not caused by disequilibrium compaction. The overpressured Jurassic sandstone reservoirs are predominantly oil and gas saturated or oil bearing. The well-log responses of the overpressured mudstones and seismic velocity characteristics indicate that the top depth of the overpressure zone ranges from 3800 to 4600 m (12,500 to 15,100 ft), corresponding to formation temperatures of approximately 94°C to 111°C (∼201°F to 232°F), with estimated vitrinite reflectance values of 0.6% to 0.75%. The Jurassic source rocks with overpressure are capable of generating hydrocarban at present and are currently overpressured. All the evidence suggests that the overpressure in the Jurassic source rocks in the central Junggar Basin is caused by hydrocarbon (HC) generation. The overpressure evolution was modeled quantitatively in response to pressure changes caused by HC generation during basin evolution. The results indicate that multiple episodes of overpressure development and release occurred within the Jurassic source rocks, suggesting multiple episodes of HC expulsion. The timing and numbers of these episodes of HC expulsion were thus determined from the modeled overpressure evolution.〈/span〉
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  • 65
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The relationship between base metal deposits, especially Mississippi Valley–type (MVT) Pb–Zn deposits, and hydrocarbons is not well constrained. This is despite the fact that hydrocarbons generally occur in MVT deposits; the ores are emplaced in the same temperature range as hydrocarbon maturation and migration, and the deposits commonly occur in proximity to metal-rich black shales. Better understanding should lead to better exploration models for both hydrocarbons and MVT deposits. This connection is better understood with the help of Pb isotope patterns. Sphalerite Pb isotope compositions from the northern Arkansas and Tri-State mining districts and Woodford–Chattanooga and Fayetteville Shales were determined to assess the potential of shales as source rocks for the ore metals. The ores in both districts have a broad range of Pb isotope ratios and define linear trends, suggesting mixing of Pb from two distinct end members. Current results and previous depositional environment studies indicate the following: (1) shales deposited mainly under nonsulfidic anoxic conditions represent the less radiogenic end member, or (2) shales are the only source of ore metals. Given the array of organic molecules, each with their own thermochemical range, and the ways metals can be associated with them, the release of metals may cover varying ranges. Thus, the compositions of the released fluids would change through time and not have a single static composition, closely approximating the isotopic composition of the released metals at various times. Mineralization derived from a dynamically evolving fluid may show apparent end members, without the need to call on mixing of fluids from separate sources.〈/span〉
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  • 66
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Twenty-four oils produced from the Woodford Shale and overlying Mississippian strata in central Oklahoma were characterized geochemically to determine their possible source(s). The 168 core samples from the Woodford and Mississippian sections of 14 wells in central Oklahoma were initially characterized by total organic carbon (TOC), Rock-Eval, and vitrinite reflectance, and select samples (TOC 〉 1.0 wt. %) were subjected to biomarker analyses to characterize source input, depositional environment, maturity, and oil-to-source rock correlations. Thermal maturity parameters indicate the Woodford Shale is immature to marginally mature in Payne County, Oklahoma, and shows a progressive increase in maturity toward the southwest. Close to the Nemaha uplift, the Woodford is in the main stage of oil generation. It is proposed that the oils in this area have three possible origins: (1) Oils produced from the Woodford and overlying Mississippian strata have similar fingerprints, suggesting the Woodford Shale and overlying Mississippian strata are in communication; (2) oils produced near the Nemaha uplift (Logan and western Payne Counties) were sourced from the Woodford but had a significant Mississippian source contribution based on source-specific biomarkers; (3) oils east of the Cherokee platform (eastcentral Payne County) share strong Woodford source characteristics, and they were not generated in situ from the immature Woodford Shale but probably migrated from the Woodford Shale in the deeper part of the Anadarko Basin in southern Oklahoma. These results are consistent with the findings that indicate abundant marine coarse-grained biogenic silica (radiolarian-rich) chert facies found in eastcentral Payne County may contribute to good reservoir petrophysical properties, suggesting the Woodford Shale may not be a source in this area but simply a tight reservoir.〈/span〉
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  • 67
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The distribution of channel deposits in fluvial reservoirs is commonly modeled with object-based techniques, constrained on quantities describing the geometries of channel bodies. To ensure plausible simulations, it is common to define inputs to these models by referring to geologic analogs. Given their ability to reproduce complex geometries and to draw upon the analog experience, object-based models are considered inherently realistic. Yet this perceived realism has not hitherto been tested by assessing the outputs of these techniques against sedimentary architectures in the stratigraphic record.This work presents a synthesis of data on the geometry of channel bodies, derived from a sedimentologic database, with the following aims: (1) to provide tools for constraining stochastic models of fluvial reservoirs in data-poor situations, and (2) to test the intrinsic realism of object-based modeling algorithms by comparing characteristics of the modeled architectures against analogs.An empirical characterization of the geometry of fluvial channel bodies is undertaken that describes distributions in (and relationships among) channel-body thickness, cross-stream width, and planform wavelength and amplitude. Object-based models are then built running simulations conditioned on six alternative, analog-informed parameter sets, using four algorithms according to nine different approaches. Closeness of match between analogs and models is then determined on a statistical basis.Results indicate which modeling approaches return architectures that more closely resemble the organization of fluvial depositional systems known from nature and in what respect. None of the tested algorithms fully reproduce characteristics seen in natural systems, demonstrating the need for subsurface modeling methods to better incorporate geologic knowledge.〈/span〉
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  • 68
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Mapping of seismic and lithological facies is a very complex process, especially in regions with low seismic resolution caused by extensive salt layers, even when only an exploratory view of the distribution of the reservoir facies is required. The aim of this study was to apply multi-attribute analysis using an unsupervised classification algorithm to map the carbonate facies of an exploratory presalt area located in the Outer high region of the Santos Basin. The interval of interest is the Barra Velha Formation, deposited during the Aptian, which represents an intercalation of travertines, stromatolites, grainstones and spherulitic packstones, mudstones, and authigenic shales, which were deposited under hypersaline lacustrine conditions during the sag phase. A set of seismic attributes, calculated from a poststack seismic amplitude volume, was used to characterize geological and structural features of the study area. We applied k-means clustering in an approach for unsupervised seismic facies classification. Our results show that at least three seismic facies can be differentiated, representing associations of buildup lithologies, aggradational or progradational carbonate platforms, and debris facies. We quantitatively evaluated the seismic facies against petrophysical properties (porosity and permeability) from available well logs. Seismic patterns associated with the lithologies helped identify new exploration targets.〈/span〉
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  • 69
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Primary depositional mineralogy has a major impact on sandstone reservoir quality. The spatial distribution of primary depositional mineralogy in sandstones is poorly understood, and consequently, empirical models typically fail to accurately predict reservoir quality. To address this challenge, we have determined the spatial distribution of detrital minerals (quartz, feldspar, carbonates, and clay minerals) in surface sediment throughout the Ravenglass Estuary, United Kingdom. We have produced, for the first time, high-resolution maps of detrital mineral quantities over an area that is similar to many oil and gas reservoirs. Spatial mineralogy patterns (based on x-ray diffraction data) and statistical analyses revealed that estuarine sediment composition is primarily controlled by provenance (i.e., the character of bedrock and sediment drift in the source area). The distributions of quartz, feldspar, carbonates, and clay minerals are controlled by a combination of the grain size of specific minerals (e.g., rigid vs. brittle grains) and estuarine hydrodynamics. The abundance of quartz, feldspar, carbonates, and clay minerals is predictable as a function of depositional environment and critical grain-size thresholds. This study may be used, by analogy, to better predict the spatial distribution of sandstone composition and thus reservoir quality in ancient and deeply buried estuarine sandstones.〈/span〉
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  • 70
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉We thank John A. Breyer and Daniel M. Jarvie for the discussion of our paper and for providing us with the opportunity to clarify the current understanding of the thermal maturity of the Mississippian Barnett Shale in the Fort Worth basin. We agree that the thermal maturity of the Barnett Shale remains under debate. Overall, the debate can be divided into two aspects: (1) absolute values and (2) causes of the spatial pattern of thermal maturity.〈/span〉
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  • 71
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Petroleum types in the Eagle Ford resource play span the range from black oil to dry gas and are produced along regional trends that are largely maturity controlled. A total of 61 shale samples covering all maturity zones were evaluated to document organic richness, organic matter type, and maturation characteristics using established geochemical parameters. Pyrolysis experiments were then performed to simulate the generation of petroleum fluids. Termed the “PhaseSnapShot” approach, one or more target wells with known fluid properties were used as reference; a match with that composition was made using next-formed fluids generated from the shale in a closely located well of slightly lower thermal maturity than the target well(s). Phase behavior predictions from the model were calibrated using a regional pressure–volume–temperature (PVT) database compiled from the public domain. The conceptual model that best matched the PVT data were comprised of two reactive components: (1) a mixture of kerogen and bitumen that generated petroleum within the low permeability shale matrix and (2) bitumen in zones of enhanced porosity within the matrix. The combined generation of gas from both of these components as well as the strong retention of C〈sub〉7+〈/sub〉 fluids in the matrix during production were required to match the calibration data. Retention of oil was needed over a broad thermal maturity range (Rock-Eval 〈span〉Tmax〈/span〉 release: 440°C –475°C). A key result of this forward model is that phase behavior and bulk compositional properties of hydrocarbons can be quickly and effectively predicted using mature shale samples as long as calibration data from PVT reports are available.〈/span〉
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  • 72
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉This study examines the influences on fluid flow within a shale outcrop where the networks of two distinct paleoflow episodes have been recorded by calcite-filled veins and green alteration halos. Such direct visualization of flow networks is relatively rare and provides valuable information of fluid-flow behavior between core and seismic scale.Detailed field mapping, fracture data, and sedimentary logging were used over a 270 m〈sup〉2〈/sup〉 (2910 ft〈sup〉2〈/sup〉) area to characterize the paleo–fluid-flow networks in the shale. Distal remnants of turbidite flow deposits are present within the shale as very thin (1–10 mm [0.04–0.4 in.]) fine-grained sandstone bands. The shale is cut by a series of conjugate faults and an associated fracture network, all at a scale smaller than seismic detection thresholds. The flow episodes used fluid-flow networks consisting of subgroups of both the fractures and the thin turbidites. The first fluid-flow episode network was mainly comprised of thin turbidites and shear fractures, whereas the network of the second fluid-flow episode was primarily small joints (opening mode fractures) connecting the turbidites.The distribution of turbidite thicknesses follows a negative exponential trend. which reflects the distribution of thicker turbidites recorded in previous studies. Fracture density varies on either side of faults and is highest in an area between closely spaced faults. Better predictions of hydraulic properties of sedimentary-structural networks for resource evaluation can be informed from such outcrop subseismic scale characterization. These relationships between the subseismic features could be applied when populating discrete fracture networks models, for example, to investigate such sedimentary-structural flow networks in exploration settings.〈/span〉
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  • 73
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The term “beef” describes bedding-parallel calcite veins found commonly in the organic-rich matrix of unconventional resource plays. Although some authors have interpreted beef to be an early diagenetic feature, these calcite veins are commonly attributed to precipitation at high temperatures and localized overpressure during hydrocarbon generation. The temperature at which the beef formed is thus crucial to ascertain the process of beef genesis. We use the novel methodology of clumped isotope analysis to constrain both the temperature at which beef forms and the isotopic composition of fluids present during formation.For this study, we use beef from basinal sections of the Vaca Muerta Formation in the Neuquén Basin, where veins are commonly up to approximately 10 cm (∼4 in.) thick and are laterally continuous over 1 km (0.6 mi). The calcite veins occur in isolation or in association with concretions and ash layers. Sequence stratigraphic boundaries have little influence on distribution, and only a low correlation between beef and total organic content or beef and ash layers exists. The internal crystal structure of beef varies largely, suggesting both syntaxial and antitaxial growth forms. The δ〈sup〉18〈/sup〉O values of beef range from approximately −12‰ to −9‰, and the δ〈sup〉13〈/sup〉C values vary between approximately −1‰ and 1‰. The surrounding mudstone and concretion fracture fills (calcite) show little difference isotopically when compared to the beef itself. The δ〈sup〉18〈/sup〉O values of nearby concretions range from approximately −3.5‰ to 1‰, and the δ〈sup〉13〈/sup〉C values vary between approximately 6‰ and 11‰.Clumped isotope analysis of beef in the Vaca Muerta Formation indicates temperatures between approximately 140°C and 195°C, whereas the surrounding mudstones vary from approximately 120°C to 150°C. The corresponding formation fluid δ〈sup〉18〈/sup〉O〈sub〉w〈/sub〉 values range from 8.5 to 14.5‰. These temperature data are higher than the maximum temperatures suggested by published studies modeling the basin’s thermal and burial histories. If these models are correct, the clumped isotope data indicate that the growth of beef in the Vaca Muerta Formation required the input of hydrothermal fluids from greater depths. Alternatively, the geothermal gradient or burial depth was underestimated in these models.〈/span〉
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  • 74
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈a href="https://pubs.geoscienceworld.org/aapgbull#b1"〉Alsalem et al. (2017)〈/a〉 present a burial history model for a well in the Fort Worth basin showing 3.7–5.2 km (2.3–3 mi) of burial during the Pennsylvanian. The generalized burial history diagram in their figure 5 suggests that vitrinite reflectance (%〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉) varies linearly with depth, or nearly so, and that %〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 values in the Barnett Shale are related primarily to depth of burial. Their modeling results indicate that the maturity of the Barnett Shale is caused by approximately 4.5 km (∼2.8 mi) of burial. 〈a href="https://pubs.geoscienceworld.org/aapgbull#b1"〉Alsalem et al. (2017)〈/a〉 do not consider any driving mechanisms for increased maturity, except heat flow through the lithosphere. If other sources of heat affected maturity values measured on organic material in the Barnett Shale, then their burial history curves would need to be modified accordingly.〈/span〉
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  • 75
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Progradation of deltaic systems that reach the shelf edge is considered a primary mechanism to deliver sand to continental margins. Sediment bypass processes can dominate the outer shelf to upper slope transition, causing poor preservation of reservoir quality sandstones. Turbidites can carry the bulk of the coarse fraction downdip where a thicker sand pile can be deposited once the channel-to-lobe transition is reached. Predicting this lateral and vertical variability along the slope is challenging. This configuration can be further complicated when mixed siliciclastic–carbonate systems are present. The Roseway–Missisauga case study from Nova Scotia is used here to explore potential implications associated with the development of deep-water turbidites that are time equivalent to outer-shelf mixed siliciclastic–carbonate units. Two scenarios are possible: (1) The carbonate factory is dominant, and the development of carbonate reefs and pinnacles on the outer shelf prevents the passage of siliciclastic systems beyond the shelf break; in this case, the siliciclastic component is sequestered within the inner-outer shelf. (2) Favorable conditions for carbonate production gradually deteriorate by the activation of fluviodeltaic systems that prograde outboard reaching the slope region. In this last scenario, low relief and lateral discontinuous carbonate shoals are ubiquitous in the outer shelf representing the last outboard remnants of the carbonate factory. Shelf-edge deltas circumvent or breach these carbonate shoals, establishing sedimentary pathways on the shelf-break region that connect with deep-water turbidites. Observations suggest that this last scenario is the most likely in this part of the Scotian margin during the Late Jurassic to Early Cretaceous.〈/span〉
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