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  • 1
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    American Physical Society (APS)
    In:  EPIC3Physical Review Letters, American Physical Society (APS), 130(18), pp. 188401-188401, ISSN: 0031-9007
    Publication Date: 2023-12-05
    Description: It has been postulated that the brain operates in a self-organized critical state that brings multiple benefits, such as optimal sensitivity to input. Thus far, self-organized criticality has typically been depicted as a one-dimensional process, where one parameter is tuned to a critical value. However, the number of adjustable parameters in the brain is vast, and hence critical states can be expected to occupy a high-dimensional manifold inside a high-dimensional parameter space. Here, we show that adaptation rules inspired by homeostatic plasticity drive a neuro-inspired network to drift on a critical manifold, where the system is poised between inactivity and persistent activity. During the drift, global network parameters continue to change while the system remains at criticality.
    Repository Name: EPIC Alfred Wegener Institut
    Type: Article , isiRev
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  • 2
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    American Physical Society (APS)
    In:  EPIC3Physical Review E, American Physical Society (APS), 105(4), pp. 044310-044310, ISSN: 2470-0045
    Publication Date: 2023-12-05
    Description: Current questions in ecology revolve around instabilities in the dynamics on spatial networks and particularly the effect of node heterogeneity. We extend the master stability function formalism to inhomogeneous biregular networks having two types of spatial nodes. Notably, this class of systems also allows the investigation of certain types of dynamics on higher-order networks. Combined with the generalized modeling approach to study the linear stability of steady states, this is a powerful tool to numerically asses the stability of large ensembles of systems. We analyze the stability of ecological metacommunities with two distinct types of habitats analytically and numerically in order to identify several sets of conditions under which the dynamics can become stabilized by dispersal. Our analytical approach allows general insights into stabilizing and destabilizing effects in metapopulations. Specifically, we identify self-regulation and negative feedback loops between source and sink populations as stabilizing mechanisms and we show that maladaptive dispersal may be stable under certain conditions.
    Repository Name: EPIC Alfred Wegener Institut
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  • 3
    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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  • 4
    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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  • 5
    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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  • 6
    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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  • 7
    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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  • 8
    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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  • 9
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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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  • 10
    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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  • 11
    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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  • 12
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    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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  • 13
    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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  • 14
    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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  • 15
    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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  • 16
    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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  • 17
    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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  • 18
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The Fuling shale gas field is located in a mountainous area, with well-developed underground rivers and karst caves. It also has a highly concentrated population, so the shale gas development in this field is faced with environmental protection problems. Combined with the characteristics of surface natural environment in the Fuling shale gas field and the features of shale gas development engineering, the main environmental issues encountered in the development of the Fuling shale gas field were analyzed. Studies on intensive land use, water conservation and protection, harmless use and disposal of oil-based drill cuttings, recycling of wastewater from drilling and fracturing, and green environment management mode for shale gas development were conducted, and the green development technology system suitable for the Fuling shale gas field was established. Field applications showed that, after applying the green development technology, the land occupation was reduced by 62.l%, the recycling rate of drilling and fracturing wastewater was up to 100%, the oil content of treated oil-based drill cuttings was less than 0.3%, and carbon dioxide emission was reduced by 64.47 × 10〈sup〉4〈/sup〉 t (1.41 × 10〈sup〉9〈/sup〉 lb). Thus, the goal of zero contamination was realized during shale gas field development. Research showed that the green and environmental protection development technology for the Fuling shale gas field has served as a valuable demonstration in the environmental protection in large-scale development of shale gas fields in China.〈/span〉
    Print ISSN: 1075-9565
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  • 19
    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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    Electronic ISSN: 1526-0984
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  • 20
    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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  • 21
    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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  • 22
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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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  • 23
    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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  • 24
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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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  • 25
    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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  • 26
    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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  • 27
    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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  • 28
    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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  • 29
    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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  • 30
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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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  • 31
    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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  • 32
    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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  • 33
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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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  • 34
    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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  • 35
    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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  • 36
    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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  • 37
    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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  • 38
    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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  • 39
    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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  • 40
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Different from most tight oil reservoirs, the tuffaceous tight oil of the Tiaohu Formation is not in situ oil, and no close contact exists between the source rock and reservoir in the Malang sag (Santanghu Basin, China). This study determined the mechanism of hydrocarbon accumulation of this tuffaceous tight oil reservoir through an integrated analysis of oil–source rock correlation, reservoir characteristics, and rock wettability combined with a comprehensive analysis of geological conditions. An oil–source rock correlation using biomarkers and stable carbon isotopes shows that the crude oil originated from underlying source rocks in the Lucaogou Formation. The oil in the tuffaceous tight reservoir is not indigenous but has migrated over a long distance to accumulate in these reservoirs. Faults and fractures that developed at the end of the Cretaceous are the oil migration pathways. Vitric and crystal-vitric tuffs constitute the main rock types of the tuffaceous tight reservoir. Matrix-related pores in the tuffs mainly comprise interparticle pores between minerals and dissolution intraparticle pores formed by devitrification. The adsorption of polar components of the oil generated from original organic matter in the tuff leads to wettability of lipophilicity, which is the main reason for hydrocarbon charging and accumulation. To our knowledge, this is the first comprehensive study reporting this finding.〈/span〉
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  • 41
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Predicting vertical and lateral facies variations in various depositional environments remains a major challenge in the oil and gas industry because it impacts petroleum system assessments and the associated exploration-risking phase. The use of multidisciplinary constraints (geomorphology, geology, geophysics) in forward stratigraphic models sheds light on the complex interaction of local, regional, and global driving mechanisms that influence sediment transport and deposition along continuously evolving landscapes. In this paper, we develop an integrated statistical approach to examine the sensitivity of forward stratigraphic models in complex salt provinces to several parameters, including water discharge, sedimentary load, grain size and associated diffusion coefficients, and slope. This statistical analysis was applied to the Barremian–Albian sequence of the central Scotian Basin (Canada) and highlights the influence of complex salt kinematics on sediment pathway diversion and accumulation around salt domes and canopies. Forward stratigraphic modeling results point to regions of higher probability of Lower Cretaceous sandy reservoirs. Automating simulation runs significantly reduced the time required to achieve a statistically valid number of simulations and allowed the sensitivity of the model to be evaluated.〈/span〉
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  • 42
    Publication Date: 2019
    Description: 〈span〉In his comment on our paper about the hyperpycnites in the Triassic Yanchang Formation, G. Shanmugam puts forward that hyperpycnites do not exist. Consequently, he considers our interpretation that hyperpycnal flows are an important depositional process in the Yanchang Formation to be invalid. We unravel his arguments and demonstrate that evidence supports our assertion that hyperpycnal flows were an important sedimentary process in the lake in which the Yanchang Formation accumulated. Moreover, we provide proof from modern observations that hyperpycnal flows do exist in lakes.〈/span〉
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  • 43
    Publication Date: 2019
    Description: 〈span〉〈a href="https://pubs.geoscienceworld.org/aapgbull#b27"〉Yang et al. (2017b)〈/a〉 have advocated the importance of hyperpycnites by using a genetic facies model proposed for deposits of hyperpycnal flows by 〈a href="https://pubs.geoscienceworld.org/aapgbull#b14"〉Mulder et al. (2003)〈/a〉. The problem is that the authors have ignored experimental flume results and other empirical field data that discredited the model. This discussion is a rigorous evaluation of data, documentation, and the facies model.〈/span〉
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  • 44
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉We analyze western Caribbean structural styles and depositional controls associated with Late Cretaceous–Cenozoic deformational events using a 1600-km (994-mi)-long, regional, northwest–southeast transect extending from the Cayman Trough in Honduras to northern Colombia. Different structural provinces defined along the transect include (1) the Cayman Trough and adjacent Honduran borderlands marking the North American–Caribbean transtensional plate boundary characterized by late Eocene–Holocene fault-controlled depocenters; (2) the Nicaraguan Rise that includes continental Paleocene–Eocene rocks deposited in sag basins, which are overlain by relatively undeformed Miocene–Holocene carbonate and clastic shelf deposits of the northern Nicaraguan Rise, following a Late Cretaceous convergent phase; (3) the Colombian Basin that includes thick Miocene clastic depocenters and the localized presence of Upper Cretaceous rocks overlying the basement and where much of the subsidence is likely isostatic and flexurally driven given its proximity to the subduction zone of northern Colombia; (4) the south Caribbean deformed belt, an active, accretionary prism produced by the subduction of the Caribbean large igneous province beneath the South American plate, which has deformed the Cenozoic prism and fore-arc section and produced thrust-fault–controlled accommodation space for upper Miocene–Holocene piggyback deposits; and (5) the onshore Cesar–Rancheria Basin in northern Colombia, which has recorded the uplift of its bounding mountain ranges, the Sierra de Santa Marta massif to the west and Perija Range to the east. Plate reconstructions place the various crustal provinces along the transect into the context of the Late Cretaceous–Cenozoic deformation events that can be partitioned into strike-slip, convergent, and extensional components.〈/span〉
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  • 45
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The lacustrine shale of the Upper Cretaceous Qingshankou Formation is the principal prospective unconventional target lithology, acting as source, reservoir, and seal. Lithofacies and associated storage capacity are two significant factors in shale oil prospectivity. This paper describes an investigation of the lower Qingshankou Formation lacustrine shale based on detailed description and analysis of cores, shale lithofacies characteristics, depositional setting, and stacking patterns.Seven lithofacies are recognized based on organic matter content, sedimentary structure, and mineralogy, all exhibiting rapid vertical and lateral changes controlled by the depositional setting and basin evolution. An overall trend from shallow-water to deep-water depositional environments is interpreted from the characteristics of the infilling sequences, characterized by increasing total organic carbon (〈span〉TOC〈/span〉) and total clay content and decreasing layer thickness (i.e., from bedded to laminated then to massive sedimentary structures). Periods of deposition during shallowing cycles show a reverse trend in the sedimentary characteristics described above. The sedimentary rocks in the studied interval show three complete short-term cycles, each one containing progressive and regressive system tracts.Massive siliceous mudstones with both high and moderate 〈span〉TOC〈/span〉 are considered to have the best hydrocarbon generation potential. Laminated siliceous mudstones, bedded siltstones, and calcareous mudstones with moderate and low 〈span〉TOC〈/span〉 could have the same high hydrocarbon saturations as the high-〈span〉TOC〈/span〉 massive siliceous mudstones, but these lithologies contain more brittle minerals than the massive mudstones. Several siltstone samples show low or zero saturation of in situ hydrocarbons; this is considered to be related to a combination of fair to poor hydrocarbon generation potential and extremely low permeability, limiting migration. Moderate-〈span〉TOC〈/span〉 laminated siliceous mudstones were also observed to have connective pore-fracture networks. It can be demonstrated that successive thick sequences of moderate-〈span〉TOC〈/span〉 laminated siliceous mudstones, showing high volumes of hydrocarbon in situ, a high mineral brittleness index, and good permeability, combine to form shale oil exploration “sweet spots.”〈/span〉
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  • 46
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Helium and nitrogen variations in Panhandle–Hugoton field (PHF) gases are products of interaction between hydrocarbon gas from the Anadarko basin and at least two water masses with dissolved nitrogen and helium. The two most distinct water masses are from the Palo Duro basin (highest He/N〈sub〉2〈/sub〉) and the Hugoton embayment (lowest He/N〈sub〉2〈/sub〉). Geochemical data indicate several hundred million years of helium generation in porous rock. Helium migrated to the gas by diffusion through water-saturated rock and by west-to-east water flow.Sediment and basement helium generation and helium migration were modeled to validate timing and source of PHF helium. Models indicate a predominantly sedimentary helium source with some basement helium charge on the Amarillo uplift. Helium in the central and eastern PHF diffused from underlying rocks, whereas gases on the west and southwest sides were enriched in nitrogen and helium delivered by hydrodynamic water flow.Nitrogen in high-nitrogen gases was probably sourced as ammonium released from clays by cation exchange with brines derived from overlying salt units. The amount of mudrock (nitrogen and helium source) relative to other potential helium sources (arkose, radioactive dolomite) correlates to decreasing gas He/N〈sub〉2〈/sub〉.The high helium concentrations in PHF gases result from multiple favorable circumstances. Old pore water accumulated dissolved helium during hundreds of millions of years of helium generation in sediment. High water/gas and low pressure favored higher helium concentrations in gas. Hydrodynamic flow delivered helium-rich pore water from basins west of the PHF.〈/span〉
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  • 47
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉As an important unconventional and alternative resource, shale gas has attracted worldwide attention. The breakthrough pressure is a major factor in the generation and migration of shale gas as well as in the evaluation of the caprock sealing capacity. Carboniferous shales are considered to have great potential for the exploitation of shale gas; thus, investigations of the breakthrough pressure and gas effective permeability are significant. Two shale samples taken from the Carboniferous Hurleg Formation in the eastern Qaidam Basin, China, were chosen to conduct breakthrough experiments to investigate the effects of water saturation and CO〈sub〉2〈/sub〉–CH〈sub〉4〈/sub〉 mixed mole fractions on the breakthrough pressure and gas effective permeability. Prior to the experiments, various relevant parameters (e.g., the porosity, mineral composition, and organic geochemistry; the total organic content, thermal maturity and kerogen type; and microstructure) of these samples were also measured.The results of our breakthrough experiments show that the breakthrough pressure increases with the water saturation and decreases with the CO〈sub〉2〈/sub〉 mole fraction in the gas mixture. The situation for the gas effective permeability is just the opposite. Pore-size distribution measurements indicate that there are many nanoscale micropores that can easily be blocked by water molecules. This results in the reduced connectivity of gas pathways; thus, the breakthrough pressure increases and the gas effective permeability decreases with increasing water saturation. The breakthrough pressure decreases with the CO〈sub〉2〈/sub〉 mole fraction because the interfacial tension of the CO〈sub〉2〈/sub〉–water system is smaller than that of the CH〈sub〉4〈/sub〉–water system. The viscosity of the CO〈sub〉2〈/sub〉–CH〈sub〉4〈/sub〉 mixture was found to increase with the CO〈sub〉2〈/sub〉 mole fraction by fitting a series of values under the same temperature and pressure conditions, leading to an increase in the gas effective permeability. Furthermore, CO〈sub〉2〈/sub〉 molecules are smaller than CH〈sub〉4〈/sub〉 molecules, making it easier for CO〈sub〉2〈/sub〉 to move across pathways. After each breakthrough experiment, the CO〈sub〉2〈/sub〉 mole fraction in the effluent was less than that in the injected gas, and it increased over time until reaching the initial injected gas composition. This is because the adsorption and solubility of CO〈sub〉2〈/sub〉 in water are greater than those of CH〈sub〉4〈/sub〉. This study provides practical information for further investigations of shale gas migration and extraction and the sealing capacities of caprocks.〈/span〉
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  • 48
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉A comprehensive study on rift stratigraphy requires a solid understanding of sequence architecture along the steep margins of rift basins. This study analyzes an Eocene lacustrine sequence along the steep margin of the Dongying depression in eastern China through integrated core, well-log, and three-dimensional seismic analyses. The lacustrine sequence is bounded by unconformities and their correlative conformities at the base and top and consists of three systems tracts, namely an early expansion systems tract (EEST), late expansion–early contraction systems tract (LEECST), and late contraction systems tract (LCST), which record a lake expansion–contraction cycle. These systems tracts differ in thickness and development of depositional systems. The EEST is the thickest and contains well-developed marginal and basinal fan systems with an overall retrogradational stacking pattern. The well-developed fan systems are the most striking features within the sequence. The LEECST is the most widespread and contains dominantly profundal–sublittoral deposits. The LCST is the thinnest, with poorly developed fan systems, and is characterized by significant erosion by fluvial incision. The variable thickness and development of depositional systems in the three systems tracts are the responses to the interplay of sediment supply and accommodation space. Accommodation space establishes the framework for sedimentary infill, and sediment supply determines spatial distribution and temporal evolution of depositional systems within each systems tract. This study provides a lake expansion–contraction scheme to divide a lacustrine stratigraphic sequence into systems tracts and highlights the feasibility of applying this approach in studying sequence stratigraphy along the steep margin of a lacustrine rift basin. The results also provide understandings for the development, distribution, and evolution of depositional systems and their controlling factors along the steep margin of other rift basins in the world.〈/span〉
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  • 49
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The purpose of this work is to identify genetic affinities among 48 crude oil samples from the onshore and offshore Santa Maria basins. A total of 21 source-related biomarker and stable carbon isotope ratios among the samples were assessed to assure that they were unaffected by secondary processes. Chemometric analysis of these data identifies six oil families with map and stratigraphic distributions that reflect organofacies variations within the Miocene Monterey Formation source rock. The data comprise a training set that was used to create a chemometric decision tree to classify newly collected oil samples. Three onshore families originated from two synclines, which may contain one or more pods of thermally mature source rock. Multiple biomarker parameters indicate that the six oil families achieved early oil window maturity in the range of 0.6%–0.7% equivalent vitrinite reflectance. The offshore oil samples consist of one family from Point Pedernales field and two families from the “B” prospect. Geochemical characteristics of these families indicate origins under differing water column and sediment oxicity and carbonate versus siliceous and detrital input in ‘carbonate,’ ‘marl,’ and ‘shale’ organofacies like those in the lower calcareous–siliceous, carbonaceous marl, and clayey–siliceous members of the Monterey Formation elsewhere in coastal California. The corresponding lithofacies and organofacies appear to be linked to the early–middle Miocene climate optimum and subsequent paleoclimatic cooling after circa 14 Ma, a systematic up-section increase in the stable carbon isotope composition of related oil samples, decreased preservation of calcium carbonate shells from planktic foraminifera and coccoliths, and increased preservation of clay-sized siliceous shells of diatoms and radiolarians. The results show that organofacies within the Monterey source rock are responsible for many of the geochemical differences between the oil families. This paleoclimate–organofacies model for crude oil from the Monterey Formation can be used to enhance future exploration efforts in many areas of coastal California.〈/span〉
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  • 50
    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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  • 51
    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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  • 52
    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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  • 53
    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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  • 54
    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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  • 55
    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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  • 56
    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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  • 57
    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〉
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  • 58
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The Pennsylvanian–Middle Triassic Cooper Basin is Australia’s premier conventional onshore hydrocarbon-producing province. The basin also hosts a range of unconventional gas play types, including basin-centered gas and tight gas accumulations, deep dry coal gas associated with the Patchawarra and Toolachee Formations, and the Murteree and Roseneath shale gas plays.This study used petroleum systems analysis to investigate the maturity and generation potential of 10 Permian source rocks in the Cooper Basin. A deterministic petroleum systems model was used to quantify the volume of expelled and retained hydrocarbons, estimated at 1272 billion BOE (512 billion bbl and 760 billion BOE) and 977 billion BOE (362 billion bbl and 615 billion BOE), respectively. Monte Carlo simulations were used to quantify the uncertainty in volumes generated and to demonstrate the sensitivity of these results to variations in source-rock characteristics.The large total generation potential of the Cooper Basin and the broad distribution of the Permian source kitchen highlight the basin’s significance as a world-class hydrocarbon province. The large disparity between the calculated volume of hydrocarbons generated and the volume so far found in reservoirs indicates the potential for large volumes to remain within the basin, despite significant losses from leakage and water washing. The hydrocarbons expelled have provided abundant charge to both conventional accumulations and to the tight and basin-centered gas plays, and the broad spatial distribution of hydrocarbons remaining within the source rocks, especially those within the Toolachee and Patchawarra Formations, suggests the potential for widespread shale and deep dry coal plays.〈/span〉
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  • 59
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The strike-slip fault systems in the central Tarim Basin, China, afford an exceptional opportunity to document the structural characteristics and evolution process of small displacement intracratonic strike-slip faults using three-dimensional seismic reflection data. These strike-slip faults display subvertical segments at depth and en echelon normal fault zones where relatively shallow. Fault segmentation and flower structures can be commonly observed in plan view and cross-section view, respectively.Consistent with the notion that segment coalescence is the fundamental process for fault evolution, the mean segment length of representative strike-slip faults examined in this study is positively correlated to the measured fault offset. The width of the en echelon normal fault zone is positively correlated with the estimated maximum overburden thickness. The integrated data sets suggest that the evolution of the conjugate fault array followed a sequential evolution process instead of forming simultaneously. The switch in slip direction of the master fault of the conjugate fault array is attributed to the change of stress orientation. Regarding individual strike-slip faults, increase in displacement induces the formation of faults with lower fault-array angles linking initially formed en echelon normal faults. In cross sections, throughgoing fault surfaces can also form, connecting the lower subvertical fault segment and the upper en echelon normal faults.The presented data sets and evolution models established in this study can be used as tools to better predict the structural attributes of subsurface strike-slip fault systems with important consequences for reservoir formation and hydrocarbon accumulation in the Tarim Basin in particular, and in ancient marine basins in general.〈/span〉
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  • 60
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Static formation temperature (〈span〉SFT〈/span〉) can be estimated from temperatures measured during wire-line logging (〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉). A large number of correction models for obtaining 〈span〉SFT〈/span〉 from 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 have been suggested. Several studies have shown that 〈span〉SFT〈/span〉s yielded by such models are off by an average of 6°C–10°C (43°F–50°F) at burial depths of 1.5–3.5 km (0.9–2.2 mi) and thus have the potential to cause serious issues in thermal and hydrocarbon generation models. This paper explores the causes for erroneous 〈span〉SFT〈/span〉 predictions generated from 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 measurements and identifies factors that should be addressed to generate a globally applicable correction model. We also present an improved empirical correction model for 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 data from eight oil and gas fields, located on the Norwegian continental shelf. The new empirical model was designed to give correct average 〈span〉SFT〈/span〉 predictions and is applicable to single 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 measurements. It has been validated against temperatures recorded during drill-stem testing, which closely represent local 〈span〉SFT〈/span〉s. The expression yields improved results compared with other correction models applied to the data set. However, the average error in computed 〈span〉SFT〈/span〉 values varies by up to 10°C (18°F) between the investigated hydrocarbon fields. We conclude that these variations result from differences in operational practices such as fluid circulation and drilling velocities. Therefore, current empirical and physical models for 〈span〉SFT〈/span〉 prediction from 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 require local calibration. It is also suggested that more accurate compilations and analyses of operational data could lead to improved and more globally applicable models.〈/span〉
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  • 61
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The petroleum system concept spans the spatial and temporal extent of all elements and processes required for the generation and preservation of petroleum. The critical moment of a petroleum system is the moment with the highest probability for the generation–migration–accumulation of hydrocarbons. It is an important concept in petroleum exploration risk assessment because the stratigraphic and geographic extents of a petroleum system are determined at the critical moment. In petroleum systems, thermal history data, burial history data, and vitrinite reflectance data may be unavailable, unreliable, or incomplete; this introduces significant uncertainty in the choice of the critical moment. We present here a quantitative probabilistic framework for estimating the critical moment and quantifying the associated uncertainty in such cases. We define a probabilistic early bound and late bound for the critical moment (which, combined together, we term the critical range) and then estimate the moment with the highest numerical probability of generation–migration–accumulation. We define the uncertainty associated with the critical moment as half the absolute value of the critical range. In cases with little ambiguity or duplicity in the timing of petroleum system elements and processes, the critical range converges to one point, which is also the critical moment. The probabilistic framework introduces consistency to the critical moment estimation problem and quantifies the level of uncertainty in the estimation. This reduces the risk involved in petroleum exploration assessment.〈/span〉
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  • 62
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Very limited literature is available relating to gas production from ultradeep (〉9000 ft [〉2700 m]) coal seams. This paper investigates permeability enhancement in ultradeep coal seams of the late Carboniferous and early Permian to Late Triassic Cooper Basin in central Australia, using a time-lapse pressure transient analysis (PTA) approach for a pilot well. The gas production history and three extended shut-in periods are used to construct the time-lapse PTA for the study well. A new approach is introduced to construct a permeability ratio function. This function allows the calculation of permeability change resulting from competition between the compaction and coal-matrix shrinkage effects.Pressure transient analysis indicates that gas flow is dominated by a bilinear flow regime in all extended pressure buildup tests. Hence, reservoir depletion is restricted to the stimulated area near the hydraulic fracture. This implies that well-completion practices that create a large contact area with reservoirs, such as multistage hydraulically fractured horizontal wells, may be required for achieving economic success in these extremely low-permeability reservoirs. The permeability ratio is constructed using the slope of the straight lines in bilinear flow analysis. Because of uncertainty in average reservoir pressure, probabilistic analysis is used and a Monte Carlo simulation is performed to generate a set of possible permeability ratio values. The permeability ratio values indicate that coal permeability has increased during the production life of the wellbore because of the coal-matrix shrinkage effect. Permeability enhancement in this ultradeep coal reservoir has offset the effect of permeability reduction caused by compaction, which is beneficial to gas production.〈/span〉
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  • 63
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Nanometer to micrometer mica and illite separates of indurated Cambrian and Ordovician oil-bearing sandstones from the Hassi Messaoud field (Algeria) were extracted, x-rayed, observed by scanning and transmission electron microscopy, and K-Ar dated. Electron microscope observations revealed typical euhedral shapes for the mica to illite particles of most size fractions; almost no odd-shaped detrital crystals were detected. The combined results document several generations of mineralogical and morphological identical mica to illite crystals that could not be differentiated by the traditional identification methods. Illite and mica genesis was multiphased with crystallization episodes at 340 ± 10 (ca. Middle Mississippian), 280 ± 10 Ma (ca. early Permian), and 170 ± 10 Ma (ca. Middle Jurassic). Younger than the stratigraphic age of the host rocks, which is incompatible with a detrital origin, the two older mica ages confirm that the hydrocarbon generation and emplacement had to start after the Variscan tectonothermal event and before exhumation of the meta-sediments. The younger K-Ar ages at 135 to 110 Ma (ca. Early Cretaceous) relate to further crystallization episodes, whereas those at circa 295, 265, and 210 Ma probably correspond to variable mixtures of the older and younger mica to illite end-members. Three average K-Ar values are statistically significant: the oldest at 340 ± 10 Ma corresponds to the start of the Variscan tectonic activity, and the intermediate at 280 ± 10 Ma sets its end, both episodes probably modifying the reservoir capacities of the potential hydrocarbon host rocks. The ages at 170 ± 10 Ma identify a further diagenetic activity characterized by illitization of dickite-type precursors in local reservoirs. These younger ages could correspond to the hydrocarbon charge into reservoirs, which stopped diagenetic illitization at a present-day depth of approximately 4000 m (∼13,000 ft).〈/span〉
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  • 64
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉This paper analyzes regional hydrogeological conditions and divides the study area into three hydrogeological types and seven hydrogeological units, to investigate hydrogeology and its effect on coalbed methane (CBM) enrichment in the southern Junggar Basin, China. From this work, it is found that the groundwater flow paths in the study area are the joint effects of south-to-north and west-to-east flows. This study also shows that microbial gases are widely developed, although the depth limit of microbial gas occurrence is still unclear in the study area. Microbial CO〈sub〉2〈/sub〉 reduction is the leading formation path in the study area, except for the Houxia region, where fermentation is the formation mechanism. The abnormally high CO〈sub〉2〈/sub〉 in stagnant zones (i.e., water flow is slow and stagnant) is mainly associated with methanogenesis, whereas relatively low CO〈sub〉2〈/sub〉 (microbial or thermogenic) is present where water flow is active. The average CBM content within the Xishanyao Formation changes within various hydrogeological units; moreover, the average CBM content within the Badaowan Formation of the same hydrogeological unit (e.g., Fukang) suggests that the hydrogeological and CBM enrichment conditions are different within various structural types. Overall, the hydrogeological conditions exert control on the gas content in the study area; that is, the gas content is high in stagnant zones. Finally, influenced by supplemental microbial gases, changes in the CBM oxidation zone are relatively complex in the study area, the depth of which has no obvious correlation with hydrogeological conditions and changes significantly from west to east.〈/span〉
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  • 65
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉How and when sediment moves from terrestrial sources to deep-water sinks is a significant area of research. We have used an array of seismic, borehole, and gravity core data sets to explore the timing and magnitude of sediment-routing to Pearl River slope over the last 478 k.y. As predicted by existing sequence stratigraphic models, most sediment dispersal to deep water is shown to have occurred during glacial sea-level falls; however, clastic detritus was still being transported into deep water during interglacial sea-level rises. We suggest that sediment routing to deep water during interglacial sea-level rise is caused by summer monsoon strengthening and resultant warmer and wetter climates, both of which have enhanced effective precipitation and sediment supply. Although some models for the delivery of sediment to deep-water basins stress the importance of proximity of canyon heads and coeval shorelines, we observed that sediment routing to deep water could occur regardless of the distance between channel head and coeval shorelines. In the present case, the success of delivery is related to the combined effects of (1) the short duration and high amplitude of sea-level oscillations during the past 478 k.y. and (2) the enhanced sediment supply caused by more humid climates and greater temperature difference between glacial and interglacial period. This hypothesis is supported by (1) observations that outer Pearl River deltas prograded as an apron over preexisting shelf edges for 10–15 km (6–9 mi) and (2) the occurrence of slope channels extending back to prodelta reaches of Pearl River shelf-edge deltas.〈/span〉
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  • 66
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The discovery of carbonate gas fields in the Middle Triassic Leikoupo Formation of the Sichuan Basin has a complex history. In recent years, a series of structural fields have been discovered in the western Sichuan Basin. Their discovery confirms the immense exploration potential of the Leikoupo Formation. In this study, we analyze the characteristics of Leikoupo Formation exploration plays using exploration wells and test data, aiming to provide a reference for further discoveries. The Leikoupo Formation represents the uppermost unit in the Sichuan marine carbonate platform succession. During its deposition, the whole basin was characterized by a restricted and evaporitic platform. Two classes of reservoirs developed. One is pore–fracture reservoirs, in marginal platform and intraplatform shoals, and another is fracture–vug reservoirs in the karstic weathering crust of the formation-capping unconformity. Three hydrocarbon accumulation models were established for the Leikoupo Formation based on the spatial and temporal relationship among the source, reservoir, and cap rocks. Two types of exploration plays are present in the Leikoupo Formation, that is, shoal (including intraplatform shoal and marginal platform shoal) dolomite plays and karstic dolomite weathering crust plays (including intraplatform shoal karst and marginal platform shoal karst). The western Sichuan depression in the karstic slope belt presents immense exploration potential because of a proximal hydrocarbon supply, charging via an extensive fracture network, shoals and karstic reservoir, a good seal rock of terrestrial mudstone, and potential composite hydrocarbon accumulations in stratigraphic traps, making it a promising area for future exploration.〈/span〉
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  • 67
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Carbonaceous debris (CD) within uranium-bearing strata has been studied in the Daying uranium deposit of the northern Ordos Basin, northern China. The influence of radiogenic heat from uranium on organic matter maturation was investigated through a series of tests including measurements of vitrinite reflectance (〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉), fission-track (FT) analysis in quartz grains, and the calculation of the radiogenic heat production rate of the samples. The results show that 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 in uranium-bearing strata generally increases as the burial depth increases, indicating that CD experienced normal burial coalification. However, 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 values of the samples rich in uranium are 0.062% 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 higher than those without uranium mineralization. Vitrinite reflectance bears a positive relationship with uranium content, and an inverse relationship with distance to the closest sandstone rich in uranium, indicating that uranium enrichment enhances organic matter maturation. The production of uranium decay makes FT observable in quartz grains, and the intensity of decay increases with proximity to the uranium ore body. The calculated radioactive heat production rate from the uranium ore body is 6.857 × 10〈sup〉−5〈/sup〉 W/m〈sup〉3〈/sup〉. During the long-term stable decay, as the uranium ore body theoretically results in an abnormal increase in temperature of 52°C without consideration of the loss of heat conduction, heat convection, and thermal radiation, this would yield a theoretical 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 increase of 0.209% 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉, reasonably greater than the observed. Therefore, the long-term stable radiogenic heat produced by uranium ore body can slightly enhance organic matter maturation, which is instructive in uranium prospecting.〈/span〉
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  • 68
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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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  • 69
    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〉
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    Topics: Geography , Geosciences
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  • 70
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The almost-pure quartz–cemented Fontainebleau Formation (Paris Basin, France) sandstones are known to preserve their porosity because of microcrystalline quartz coatings. Here, we use nuclear magnetic resonance (NMR) techniques, petrography, scanning electron microscopy, porosity and permeability measurements, hysteresis, and mercury injection capillary pressure curves to identify and analyze their porosity structure. Nuclear magnetic resonance experiments include transverse relaxation time (〈span〉T〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉) distributions and 〈span〉T〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉-filtered 〈span〉T〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉–〈span〉T〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉 exchange (〈span〉T〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉F-TREx), a technique that provides estimates on the diffusion coupling by comparing the evolution of families of pores in 〈span〉T〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉 distributions at different exchange times. Samples were divided according to their texture, composition, and abundance of microcrystalline quartz crystals, comprising group 1 samples with very low amounts of coatings and group 2 samples with entire grains coated by microquartz. Both groups show three (or four) peaks in NMR 2-MHz 〈span〉T〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉 distribution at approximately 1 (peak A), 10〈sup〉−1〈/sup〉 (peak B), and 10〈sup〉−2〈/sup〉 s (peak C); group 2 samples present a slight shift to shorter 〈span〉T〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉 times in comparison with other samples. The longest 〈span〉T〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉 peak A is because of intergranular macropores, whereas the shortest peak C is because of the microporosity associated with the microcrystalline quartz coating at the surface of the pores. Peak B is also because of microporosity associated with microcrystalline quartz, but with a different surface/volume ratio being likely related to flat-shaped pores within the microcrystalline coating. The 〈span〉T2〈/span〉F-TREx indicates the proton exchange is higher between macropores and the pore surface micropores (peak C) than between macropores and the internal flat-shaped micropores; no exchange between the two sets of micropores can be observed. Our results show the potential of NMR techniques in characterizing the microporosity in Fontainebleau sandstones, which is key for the mechanism of porosity preservation in these rocks.〈/span〉
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  • 71
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Free and sorbed low-to-medium molecular weight thermovaporized hydrocarbons (〈C〈sub〉20〈/sub〉) are the main organic compounds released at the temperature range corresponding to the Rock-Eval〈sup〉®〈/sup〉 Shale Play〈sup〉TM〈/sup〉〈span〉Sh〈/span〉〈span〉0〈/span〉 parameter (100°C–200°C), whereas medium and high molecular weight thermovaporized compounds (〈 C〈sub〉30〈/sub〉) are the predominant components that are thermal released in the temperature range corresponding to the Shale Play 〈span〉Sh1〈/span〉 parameter (200°C–350°C). Now, an analytical methodology is proposed here to predict the quantity of free versus sorbed hydrocarbons still present in any liquid-rich sedimentary rock. The method compares shale play parameters (〈span〉Sh0〈/span〉 and 〈span〉Sh1〈/span〉) obtained from both whole-rock samples and their corresponding organic matter (OM) concentrates isolated by standard nonoxidizing acid treatments and drying procedures. The hydrocarbon content obtained from whole rock (〈span〉HC〈/span〉〈sub〉〈span〉Total,rock〈/span〉〈/sub〉) is mainly considered as the total amount of free liquid hydrocarbons (〈span〉HC〈/span〉〈sub〉〈span〉Free〈/span〉〈/sub〉) and sorbed liquid hydrocarbons (〈span〉HC〈/span〉〈sub〉〈span〉Sorbed,OM〈/span〉〈/sub〉) still contained in the investigated rock sample.The hydrocarbon content obtained from OM concentrates, however, only reflects the sorbed liquid hydrocarbons.In these equations, 〈span〉TOC〈/span〉〈sub〉〈span〉rock〈/span〉〈/sub〉 is the total organic carbon of the rock sample; 〈span〉TOC〈/span〉〈sub〉〈span〉OM〈/span〉〈/sub〉 corresponds to the 〈span〉TOC〈/span〉 content of the OM concentrate sample; 〈span〉Mass〈/span〉〈sub〉〈span〉rock〈/span〉〈/sub〉 is the initial mass of the rock sample; 〈span〉Mass〈/span〉〈sub〉〈span〉OM〈/span〉〈/sub〉 is the initial mass of the OM concentrate sample; 〈span〉FIDsignal〈/span〉〈sub〉〈span〉rock〈/span〉〈/sub〉〈sup〉〈span〉Sh0+Sh1〈/span〉〈/sup〉 is the flame ionization detection (FID) signal that corresponds to the global surface area under each thermal peak (〈span〉Sh0〈/span〉 and 〈span〉Sh1〈/span〉) generated by the Rock-Eval FID; 〈span〉FIDsignal〈/span〉〈sub〉〈span〉OM〈/span〉〈/sub〉〈sup〉〈span〉Sh0+Sh1〈/span〉〈/sup〉 corresponds to the global surface area under each thermal peak (〈span〉Sh0〈/span〉 and 〈span〉Sh1〈/span〉) measured by the Rock-Eval FID between 100°C and 350°C after the themovaporization of the OM concentrate sample. Free liquid hydrocarbons are finally calculated as the difference between these last two values (〈span〉HC〈/span〉〈sub〉〈span〉Free〈/span〉〈/sub〉 = 〈span〉HC〈/span〉〈sub〉〈span〉Total,rock〈/span〉〈/sub〉 − 〈span〉HC〈/span〉〈sub〉〈span〉Sorbed,OM〈/span〉〈/sub〉). This paper illustrates the application of this methodology on rock samples derived from the Vaca Muerta Formation (Argentina). Along the selected vertical profile, the lower rock interval contains approximately 60% of sorbed liquid hydrocarbons, whereas the upper sample contains more than 90% free liquid hydrocarbons. The parameters 〈span〉FreeHC〈/span〉〈sup〉〈span〉Sh0〈/span〉〈/sup〉 and 〈span〉FreeHC〈/span〉〈sup〉〈span〉Sh0〈/span〉〈/sup〉〈sup〉+〈/sup〉〈sup〉〈span〉Sh1〈/span〉〈/sup〉 could be used to identify potential producible free liquid hydrocarbons intervals in early exploration campaigns.〈/span〉
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  • 72
    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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  • 73
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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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  • 74
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉This paper clarifies the controls of oil retention in the Niobrara Formation, Denver Basin, in the western United States. Sweet spots have been recognized using a total of 98 core samples from 5 wells with maturities covering the oil window.Oil retention in the source rock samples (carbonate content 〈70 wt. %) is controlled by organic matter richness and thermal maturity. In general, the vaporizable hydrocarbon (HC) yield at nominal temperatures at 300°C ([〈span〉S1〈/span〉]; Rock-Eval) is positively correlated to total organic carbon (〈span〉TOC〈/span〉). With increasing maturity, the so-called oil saturation index (〈span〉S〈/span〉〈sub〉〈span〉1〈/span〉〈/sub〉/〈span〉TOC〈/span〉 × 100) first increases until a maximum retention capacity (100 mg HC/g 〈span〉TOC〈/span〉) is exceeded at the temperature at the maximum rate of petroleum generation by Rock-Eval pyrolysis (〈span〉T〈/span〉〈sub〉〈span〉max〈/span〉〈/sub〉) of approximately 445°C and subsequently decreases. The depletion in oil retention capacity is believed to be associated with the appearance of organic nanopores.Oil retention in samples with distinct reservoir potential (carbonate 〉30 wt. %) is controlled by carbonate content, which is positively related to the amount of retained oil. Petrographic features indicate that oil or bitumen is stored in porous calcite fossils (i.e., coccolith and foraminifera), which provide additional space for petroleum storage. Chalk samples (carbonate 〉85 wt. %) are characterized by anomalously low 〈span〉T〈/span〉〈sub〉〈span〉max〈/span〉〈/sub〉 values caused by the influence of heavy petroleum or bitumen. The amount of this bitumen is higher than the initial petroleum potential of kerogen in A and B chalks and thus must have been emplaced here. The most likely sources are juxtaposed organic-rich marl layers.Thus, sweet spots occur where carbonate content is either low (high 〈span〉TOC〈/span〉) or high (low 〈span〉TOC〈/span〉), whereas production of petroleum from the pore space of presumably brittle chalk seems more attractive than production from organic- and clay-rich rocks.〈/span〉
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  • 75
    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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  • 76
    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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  • 77
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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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  • 78
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉The nanometer-scale architecture of organic matter (OM) and associated pores in highly mature gas shales from the lower Silurian Longmaxi Formation in the upper Yangtze platform of south China were investigated using field emission scanning electron microscopy (SEM), focused ion beam SEM, and low-pressure gas (N〈sub〉2〈/sub〉 and CO〈sub〉2〈/sub〉) adsorption bulk pore characterization. The Longmaxi shale comprises fine-grained siliciclastic rocks deposited in a marine shelf environment, which was dominated by quartz and clay minerals. Four porous OM types were found in the Longmaxi shale on the basis of the chemical composition and spatial occurrence of OM, including (1) isolated original OM particles, (2) OM–clay mineral complexes, (3) OM–heavy mineral complexes, and (4) secondary migrated bituminous OM. The pores in the particulate OM are not homogeneously distributed, and the processes leading to different pores depend on the specific OM type. The nature of OM-hosted pores is a result of several factors, such as primary porous kerogen, mechanical compaction, organic–inorganic interactions, gaseous and liquid hydrocarbon generation, retention, and expulsion. Pore volumes and specific surface areas of the Longmaxi shale derived from low-pressure N〈sub〉2〈/sub〉 and CO〈sub〉2〈/sub〉 adsorption experiments reveal positive linear relationships with total organic carbon contents, which indicates that the pore systems in the highly mature Longmaxi shale are dominated by OM-hosted pores. Additionally, the OM-hosted pores appear connected compared to pores in the mineral matrix. Therefore, the OM-hosted pore systems offer the preferential storage space and primary migration pathways for natural gas in the Longmaxi shale reservoir.〈/span〉
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  • 79
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Reservoir quality (RQ) prediction models for sandstones in use by the oil and gas industry primarily emulate mechanical compaction, quartz cementation, and cementation by a few select aluminosilicate minerals during burial. The modeled cements are treated on a kinetic basis using independent Arrhenius-style rate equations, and nonmodeled cements are constrained by empirical observations and data from analog rocks. The nonmodeled cements pose a significant modeling challenge in complex lithic and arkosic sandstones that contain carbonate, clay, or zeolite cements when analog data are not available for constraint. Twenty-nine samples covering a broad range of sandstone compositions were selected from four fields in four different sedimentary basins to investigate the potential of using modern reactive transport models (RTM) to simulate a more comprehensive suite of minerals involved in sandstone diagenesis. A commercially available RTM, GWB〈sup〉®〈/sup〉 X1t, was configured to model chemical diagenesis in a time–temperature burial framework conceptually similar to that employed in standard industry RQ forward models. Strategies were developed to consistently constrain kinetic parameters, fluid compositions, and fluid fluxes with the goal of standardizing these parameters to reduce configuration and calibration time. Results show that RTM using such standardized parameters can reproduce relative timing and volume changes caused by mineral dissolution and precipitation that are accurate within the uncertainty of the petrographic data constraint. The results suggest that incorporation of RTM into current industry models could provide a valuable improvement to siliciclastic RQ prediction in frontier plays with complex mineralogies wherever calibration data are sparse or unavailable.〈/span〉
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  • 80
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Six southern Texas Eagle Ford cores were investigated to quantify mineralogical composition and total organic carbon (〈span〉TOC〈/span〉). Machine learning of the x-ray fluorescence (XRF) data set was conducted using neural network analysis to predict mineralogies for L1, L2, and L3 and 〈span〉TOC〈/span〉 for L1, L2, L3, Iona-1, Innes-1, and well “X.” Inees-1 and well “X” were used as blind tests to check the quality of the developed models. The online Neural Designer software was used to perform the training process and develop models. Quantitative laboratory-measured x-ray diffraction (XRD) mineralogies and 〈span〉TOC〈/span〉 were used to conduct the training and develop high-resolution semiquantitative models, and the derived mineralogic and organic matter models were found to be promising. The modeled mineralogy and 〈span〉TOC〈/span〉 represent continuous relative abundances, which are far more significant than scattered individual XRD and 〈span〉TOC〈/span〉 point measurements. The significance of this study is that it allows for the use of relatively inexpensive and nondestructive XRF analysis that requires minimal sample preparation to construct high-resolution mineral abundances and 〈span〉TOC〈/span〉 content. With modern advances in technology, XRF can now be measured on drill cuttings in real time while drilling is occurring, allowing operators to use the proposed method to construct semiquantitative mineralogical and 〈span〉TOC〈/span〉 models for evaluating placement of laterals in prospective intervals and designing completion techniques accordingly.〈/span〉
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  • 81
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉This paper investigates transport mechanisms involving carbonate cementation in Eocene, tight-oil sandstones in Bohai Bay Basin, China, to determine potential mass transfer between adjacent mudstones and sandstones. Evidence from petrology, geochemistry, and numerical modeling suggests two generations of carbonate cementation: (1) early nonferroan calcite (formed at 28°C–41°C) and dolomite (formed at 45°C–63°C); and (2) later ferroan calcite (formed at 105°C–124°C) and ankerite (formed at 101°C–137°C). Based on a one-dimensional model for a coupled sandstone–mudstone system under low and high temperatures, different distribution patterns of carbonate cements reflect episodic concentration gradients that led to diffusive transport of bicarbonate species during progressive burial. Firstly, extensive precipitation of early nonferroan calcite followed by dolomite at or near mudstone–sandstone contacts resulted from initial concentration gradients related to different compositions in primary mineral assemblages. Secondly, introduction of aqueous CO〈sub〉2〈/sub〉 from adjacent mudstones into sandstones resulted in dissolution of early nonferroan carbonates and led to diffusive transport of bicarbonate species. These bicarbonate species were incorporated with Fe〈sup〉2+〈/sup〉 and subsequently reprecipitated as ferroan carbonate minerals at distances greater than 2 m (〉6.6 ft) from sandstone–mudstone contacts. Therefore, short-distance diffusive transport is inferred to have been the predominant transport mechanism associated with carbonate cementation. Large-scale mass transfer between sandstones and adjacent mudstones occurred in a relatively open geochemical system on a very local scale. Numerical model results show that low porosity zones (2.6%–5.1%) exhibit coherence with high abundances of carbonate cements (13.9%–21.2%). Tightly cemented intervals were created by different generations of carbonate cementation and resulted in destruction of sandstone reservoir porosity.〈/span〉
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  • 82
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Six distinct oil tribes were established using multivariate statistical analysis of source-related biomarker and isotopic ratios for 73 crude oil samples from the Middle Magdalena Valley (MMV), Colombia. These six tribes show a systematic distribution by both basin location and reservoir rock age and may originate from different source rocks or different organofacies of the same source rock. Biomarker and isotopic data further differentiate the tribes with respect to source rock depositional environment, lithology, organic matter type, and thermal maturity. The thermal maturity and reservoir interval for the northernmost tribe 5 suggest a middle Cretaceous Tablazo Formation source rock. In contrast, tribes 1 through 4 are likely derived from the primary regional source rock, the Upper Cretaceous La Luna Formation. However, we observe regional differences in bulk properties, thermal maturity, terrigenous input, and oxicity between the four La Luna–derived oil tribes. In addition, tribe 3 appears to result from end-member mixing between tribes 2 and 4. Finally, the southernmost tribe 6 is the only oil with terrigenous character. Diamondoid analysis shows the presence of significant secondary cracking in the tribe 6 oil with low levels of cracking present in oil samples from tribes 1 and 2 in the central MMV. This suggests a more deeply buried nonmarine source along the western flank of the Andean Eastern Cordillera. The integration of chemometric, biomarker, and diamondoid analyses have improved our understanding of the MMV petroleum system and advocate for the presence of three or more source rock intervals within the basin.〈/span〉
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  • 83
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉To investigate the mechanism of local porosity modification in a carbonate reservoir caused by the acidic components associated with natural gas generation, a numerical model for the charging of natural gas rich in acidic components (CO〈sub〉2〈/sub〉) was developed. The acidic components are originated from maturation of organic matter in the source rock. The model includes coupled gas–water–rock interactions, multiphase flow, and spatial heterogeneities of the geochemical reactions.The simulation results indicate the following. (1) When regional groundwater travels through the gas–water contact (GWC), it is acidified by the CO〈sub〉2〈/sub〉(g) in the gas zone and will dissolve carbonate minerals to form local secondary porosity. The generated local secondary porosity is approximately 0.04 (volume fraction), with a maximum value of approximately 0.27, and is located mainly in the vicinity of the GWC. (2) Under reservoir conditions, the solubility of calcite is much higher than dolomite. The higher solubility and common ion effect of Ca results in calcite being the primary reactive mineral in pure carbonate reservoirs (having both calcite and dolomite). The presence of anhydrite in the system does not change this situation. (3) The groundwater flow field causes GWC evolution to be S-shaped. The inflection and gentle-sloping parts at both ends of the GWC have different angles with the groundwater stream lines, resulting in different amounts of mineral dissolution and precipitation and porosity increase. (4) The limited amount of CO〈sub〉2〈/sub〉 from the source rock and groundwater flow in the subsurface seems to be sufficient to support local secondary porosity generation.〈/span〉
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  • 84
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉High-resolution digital outcrop models of stacked deep-water channel elements are constructed from the Laguna Figueroa section of the well-exposed Upper Cretaceous Tres Pasos Formation in Chilean Patagonia. The models are based on greater than 1600 m (〉5250 ft) of centimeter-scale measured sections, greater than 100 paleoflow measurements, and thousands of differential global positioning system points (10-cm [4-in.] accuracy) from an outcrop belt that is approximately 2.5 km (∼1.5 mi) long and 130 m (425 ft) thick. The models elucidate the effects bed-to-geobody–scale architecture has on static sandstone connectivity among a series of stacked deep-water channel elements and how that connectivity is altered by grid cell size.Static connectivity analyses show that channel element base drapes can strongly influence sandstone connectivity and that smaller channel element widths are more likely to produce disconnected sandstone geobodies. Net-to-gross (NTG) is not directly correlated with connectivity because of the presence of thin channel element base drapes, which do not significantly contribute to NTG. Upscaling the models consistently increases channel element contact (up to 10%) but decreases sandstone connectivity (up to 2%–3%). Channel element stacking patterns strongly impact connectivity. For example, connectivity is reduced in cases of high lateral channel element offsets. Increasing drape coverage markedly decreases connectivity. Evaluating connectivity in a vertical, along-system profile is critical to understanding flow units and reservoir piping. Ultimately, this work constrains uncertainty related to the impact of subseismic-scale stratigraphic architecture on reservoir connectivity by providing concrete knowledge that can be used to guide the model building process.〈/span〉
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  • 85
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Landslides are geologic events that cost Pennsylvania $127 million in 2018. Landslide susceptibility models, or maps that depict where landslides are likely to occur, are helpful tools for the public and private sectors to use to mitigate the cost and damage caused by mass movements. However, Pennsylvania’s most current statewide susceptibility map for landslides is broad and only suitable for analysis at the state level. The majority of northeastern Pennsylvania (NEPA) falls within a low susceptibility zone, but within this zone are undefined areas of moderate to high susceptibility. This broad range of susceptibility provides no slope-specific description of the moderate to high classifications. Pennsylvania’s coarse resolution susceptibility model is likely caused by the lack of a comprehensive landslide inventory for the entire state that might be used in data-driven methods of susceptibility modeling. To create a high-resolution susceptibility map for NEPA, a landslide inventory for NEPA was constructed based on enhanced imagery and analysis of light detection and ranging–derived digital terrain models. A data-driven bivariate frequency ratio method was used for the creation of a 30-m pixel-resolution susceptibility map that is both qualitatively and quantitatively more robust than the most current model within the region. Our results indicate that within NEPA, slope failures are most influenced by the slope derivative of elevation. Slopes are most susceptible to failure along steep valleys created by rivers and streams within the Appalachian Plateau, as well as areas with steep slope within the Ridge and Valley areas of the study region.〈/span〉
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    Electronic ISSN: 1526-0984
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  • 86
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Subsurface disposal of salt water coproduced with oil and gas has become a critical issue in the United States because of linkages with induced seismicity, as seen in Oklahoma and northcentral Texas. Here, we assess the spatiotemporal and stratigraphic variations of salt-water disposal (SWD) volumes in the Permian Basin. The results of this analysis provide critical input into integrated assessments needed for handling of produced water and for emerging concerns, such as induced seismicity.Wellbore architecture, permits, and disposal volumes were compiled, interpreted for disposal intervals and geologic targets, and summarized at formation, subregion, a 100-mi〈sup〉2〈/sup〉 (260-km〈sup〉2〈/sup〉) area, and monthly volumes for the years 1978–2016. Geologic targets were interpreted by intersecting the disposal intervals with gridded stratigraphic horizons and by reviewing well logs where available.A total of 30 billion bbl (∼5 trillion L) were disposed into 73 geologic units within 6 subregions via 8201 active SWD wells for 39 yr. Most disposal occurred in the Midland Basin and Central Basin Platform (CBP) over the first 34 yr but shifted from the CBP to the Delaware Basin over the last 5 yr (2011–2016) with the expansion of unconventional oil and gas production. Approximately half of the salt water is disposed above the major unconventional reservoirs into Guadalupian-aged formations, raising concerns of overpressuring and interference with production. Operators are exploring deeper SWD targets; however, proximity to crystalline basement poses concerns for high drilling costs and the potential for induced seismicity by reactivation of deep-seated faults.〈/span〉
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  • 87
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Thin-section analysis, field emission scanning electron microscopy, constant-rate mercury injection (CRMI), x-ray–computed tomography (X-CT), and nuclear magnetic resonance (NMR) were used to investigate pore systems, pore sizes, and pore-throat distributions and determine evaluation criteria for tight oil reservoirs.This research shows that the average porosity of the reservoirs in the Chang 6〈sub〉3〈/sub〉 to Chang 7〈sub〉2〈/sub〉 Members of the Yanchang Formation of the Ordos Basin ranges from 4% to 16%, with a corresponding average permeability of 0.1 to 0.4 md. The main pore types in these tight oil reservoirs are dissolution pores and intergranular pores, and the main pore-throat types are laminated throats and control-shaped throats. Based on experimental results, the pore-throat distributions differ among different testing techniques. The results of this study indicate that a combination of CRMI-derived and X-CT–detected pore-throat distributions is most suitable for calibrating NMR-derived pore sizes over the full range of pore sizes. The lower pore-throat radius limit of effective reservoirs is 0.24 μm, and the lower permeability limit for the flow of movable fluid is 0.008 md. Based on a cluster analysis, the studied tight oil reservoirs can be divided into three types. Compared with type III reservoirs (porosity 〈 8% and 0.008 md 〈 permeability 〈 0.05 md), type I (porosity 〉 11% and permeability 〉 0.15 md) and type II (8% 〈 porosity 〈 11% and 0.05 md 〈 permeability 〈 0.15 md) reservoirs are of relatively good quality.〈/span〉
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  • 88
    Publication Date: 2019
    Description: 〈span〉〈div〉ABSTRACT〈/div〉Siliciclastic turbidite systems that pinch out updip toward their proximal margin are prime targets for hydrocarbon exploration, especially in deep-water basins. Such “upslope stratigraphic traps” potentially offer large-volume discoveries but have significant geological risks, notably because of ineffective closure or containment. In the published literature, at least 20 fields from 11 basins globally with 6–7 billion BOE of cumulative discovered reserves have been inferred to be reliant on upslope pinchout traps. These fields are reviewed in terms of their interpreted trapping styles, pinch-out formation process, and depositional-tectonic setting. Reservoirs display a range of upslope trapping styles, including pure (depositional and erosional) stratigraphic pinch-outs and combined stratigraphic-structural traps. In one-third of cases, faulting appears intimately linked to updip trapping, either through offsetting slope feeder conduits or assisting pinch-out development, and in some cases, faulting may be the most important updip trapping element. Sediment bypass and erosion in proximal areas is the most common inferred pinch-out formation mechanism. Some reservoirs also demonstrate the ability of erosional truncation by mud-prone channels and mass transport deposits to form viable stratigraphic traps and seals. Encouragingly for exploration, robust pinchout traps occur in various tectonic settings on a variety of different slope types and positions along the slope profile. Most large-volume discoveries to date, however, are restricted to the toe-of-slope environment in graded passive margins or out-of-grade rift and transform margin settings. Insights into the nature and occurrence of upslope stratigraphic traps are important for future exploration, especially for evaluating new license areas and risking prospects.〈/span〉
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  • 89
    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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  • 90
    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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  • 91
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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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  • 92
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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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  • 93
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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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  • 94
    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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  • 95
    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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  • 96
    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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  • 97
    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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  • 98
    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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  • 99
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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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  • 100
    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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