Journal articles: 'Rock evaluation pyrolysis'

1

MACHIHARA, Tsutomu. "Source Rock Evaluation by Pyrolysis-GC." Journal of the Japanese Association for Petroleum Technology 53, no. 3 (1988): 223–29. http://dx.doi.org/10.3720/japt.53.223.

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Su, Siyuan, Zhenxue Jiang, Zhiye Gao, Chuanxiang Ning, Zhi Wang, Zheng Li, and Rifang Zhu. "A new method for continental shale oil enrichment evaluation." Interpretation 5, no. 2 (May 31, 2017): T209—T217. http://dx.doi.org/10.1190/int-2016-0158.1.

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We have evaluated continental shale oil enrichment via experiments. Rock pyrolysis, nuclear magnetic resonance, and pulse permeability tests were conducted to establish the pore saturation index (PSI), which comprehensively evaluates the enrichment of shale oil features using the characteristics of self-generation and self-preservation, the parameters of which include the pyrolysis-free hydrocarbon ([Formula: see text]) and total organic carbon of source rocks as well as the porosity and permeability of reservoir rocks. The correlation of the oil content ([Formula: see text]) and PSI values indicated that PSI values greater than 50 generally indicate good oil enrichment plays, whereas those smaller than 50 imply poor conditions for oil enrichment. This conclusion was successfully applied to the Zhanhua Sag with shale oil plays in the Jiyang Depression, Bohai Bay Basin, China. In addition, the shale oil plays of the Dongying Sag in the Jiyang Depression were investigated to verify the effectiveness and reliability of the new method.

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Więcław, Dariusz, and Maria Sadlik. "Evaluation of ground pollution by hydrocarbons using Rock-Eval pyrolysis." Polish Journal of Chemical Technology 21, no. 3 (September 1, 2019): 8–12. http://dx.doi.org/10.2478/pjct-2019-0023.

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Abstract The exploration and utilization of petroleum are potential hazards to the environment. Successful determination of petroleum contamination in ground relies on accurate definition of the type, source and quantity of contaminant. For this purpose the Rock-Eval® pyrolysis was applied, which is a rapid quantitative (Bulk Rock method) and qualitative (fractional composition using Multi-Heating Rates method) technique. Results of Rock-Eval analysis of 13 samples of concrete and 2 samples of gravel taken from the different sites of the petrol station indicate the highest concentration of light hydrocarbons (gasoline and naphtha fractions), up to over 5% wt. in the direct proximity of petrol pumps. Similarly high contamination (almost 4%wt.), was found near fuel tanks. Here the highest contribution has lubricating oil fraction and the tankers providing fuels are probably the source of this pollution. In the gravel collected in the vicinity of the fuel tanks high concentration (over 5 wt.%) of non-pyrolyzable carbon (soot) was recorded, the source of which are probably diesel engines of fuel tankers supplying fuel.

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Sun, Fengyu, Gaoshe Cao, Zhou Xing, Shuangjie Yu, and Bangbang Fang. "Characteristics and evaluation of the Upper Paleozoic source rocks in the Southern North China Basin." Open Geosciences 13, no. 1 (January 1, 2021): 294–309. http://dx.doi.org/10.1515/geo-2020-0221.

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Abstract The Upper Paleozoic coal measure strata in the Southern North China Basin have good potential for unconventional oil and gas exploration. However, there has been no systematic evaluation of potential source rock in this area; this affects the estimation of potential resources and the choice of exploratory target layers. In this study, full core holes ZK0901 and ZK0401, which perfectly reveal Upper Paleozoic strata in the study area, systematically collected and analyzed the samples for total organic carbon, rock pyrolysis, chloroform bitumen “A,” organic maceral, vitrinite reflectance, and kerogen carbon isotopes. The results showed that in addition to coal rocks, mudstones and carbonate rocks are also potential source rocks in the Upper Paleozoic strata. Vertically, the source rocks are continuous in Taiyuan Formation, the lower part of Shanxi Formation, and Lower Shihezi Formation. The organic matter type in the Upper Paleozoic coal rocks and mudstone source rock belong to type III or II. This phenomenon is mainly attributed to the special transgressive–regressive sedimentary environment of the carbonate rocks. The higher degree of thermal evolution in the Upper Paleozoic source rocks may be related to the structure or a higher paleogeothermal gradient in this area. The coal layer and its upper and lower mudstone of the Shanxi Formation and Lower Shihezi Formation are the main target layers of unconventional oil and gas exploration. The results from this study can be used as a reference for the study on potential source rock for unconventional oil and gas exploration in the Southern North China Basin.

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Faqi, Ayad, Ali Ali, Bahjat Abdullah, and Stephen Bowden. "Source Rock Evaluation and Lateral Changes in Thermal Maturity of the Sargelu Formation (Middle Jurassic) in Kurdistan Region-Northern Iraq." UKH Journal of Science and Engineering 2, no. 1 (June 30, 2018): 7–17. http://dx.doi.org/10.25079/ukhjse.v2n1y2018.pp7-17.

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In this study, source rock characteristics and lateral changes in thermal maturity of the Sargelu Formation (Middle Jurassic) in three outcrops were studied. The formation’s outcrops can be found in the High Folded, and Imbricated Zones of Iraqi Tectonic Division. In order to achieve the main goals of this study, the Gas chromatography mass spectrometry (GC-MS) and Rock-Eval pyrolysis were performed on the organic matter (OM) of the Sargelu sediments. Pristane/Phytane ratios for analyzed samples indicate reducing conditions (anoxic) during sedimentation. Moreover, based on C29/C30 hopanes ratios the sediments of the Sargelu Formation associated with clay- rich source rock. Biomarker thermal maturity parameters display that all samples are thermally in Oil Window at least. The biomarker findings reveal that the samples of Walasimt and Barsarin are seem more mature than Banik section. The values for TOC% of the Sargelu Formation may show Excellent, Very Good, and Poor quality source rock. The Pyrolysis executed for studied samples revealed the kerogen in Banik section belongs to Types II and III (Probably Oil/Gas- prone), while Barsarin and Walasimt sections obtained Types III-IV Kerogen (Gas- prone). Pyrolysis parameters suggested Early Mature Stage in Banik, While Overmature in Barsarin and Walasimt. The data also shows that organic matter of the Sargelu Formation in Banik section is in Oil Widow, while in Barsarin and Walasimt is in Gas Window.

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Abdula, Rzger, Kamal Kolo, Maria-Elli Damoulianou, Victoria Raftopoulou, Polla Khanaqa, and Stavros Kalaitzidis. "Rock-Eval analysis and organic petrographical characterization of the Upper Jurassic Naokelekan Formation, northern Mesopotamian basin, Kurdistan Region-Iraq." Bulletin of the Geological Society of Greece 56, no. 1 (July 23, 2020): 187. http://dx.doi.org/10.12681/bgsg.22842.

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The aim of this study is to assess the type, thermal maturity and the petroleum generation potential of the Upper Jurassic Naokelekan Formation, occurring across the Kurdistan Region of Iraq, by applying organic petrographical methods and Rock-Eval analysis. The Rock-Eval data would indicate the presence of kerogen types III, IV and II as the main constituents. However, the qualitative petrographical evaluation revealed that the main organic constituents are solid hydrocarbons, in the form of microgranular migrabitumens, with minor amounts of pyrobitumens. These secondary particles have affected the results of the Rock-Eval analysis and would have led to misinterpretation of organic matter typification based on pyrolysis results only. The combined results of petrography and pyrolysis indicate an active petroleum system within the Upper Jurassic sequence, where hydrocarbons are generated and reservoired within suitable lithologies.

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MACHIHARA, Tsutomu. "Source rock evaluation by pyrolysis-GC. Part 1. Type analysis of kerogen." Journal of the Japanese Association for Petroleum Technology 52, no. 6 (1987): 511–19. http://dx.doi.org/10.3720/japt.52.511.

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Spasennykh, Mikhail, Polina Maglevannaia, Elena Kozlova, Timur Bulatov, Evgeniya Leushina, and Nikita Morozov. "Geochemical Trends Reflecting Hydrocarbon Generation, Migration and Accumulation in Unconventional Reservoirs Based on Pyrolysis Data (on the Example of the Bazhenov Formation)." Geosciences 11, no. 8 (July 24, 2021): 307. http://dx.doi.org/10.3390/geosciences11080307.

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The current study is devoted to the determination and interpretation of geochemical trends reflecting hydrocarbon generation, migration and accumulation in unconventional reservoirs; the study is performed on the Bazhenov shale rock formation (Western Siberia, Russia). Results are based on more than 3000 Rock-Eval analyses of the samples from 34 wells drilled in the central part of the West Siberian petroleum basin, which is characterized by common marine sedimentation environments. Pyrolysis studies were carried out before and after the extraction of rocks by organic solvent. As a result, we have improved the accuracy of kerogen content and maturity determination and complemented the standard set of pyrolysis parameters with the content of heavy fraction of hydrocarbons. The data obtained for the wells from areas of different organic matter maturity was summarized in the form of cross-plots and diagrams reflecting geochemical evolution of the source rocks from the beginning to the end of the oil window. Interpretation of the obtained results revealed quantitative trends in the changes of generation potential, amount, and composition of generated hydrocarbons in rocks at different stages of oil generation process. The analysis of geochemical trends allowed us to improve approaches for the productivity evaluation of the formation and study the effect of organic matter maturity on distribution of productive intervals of different types.

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Summons, Roger E., Dennis Taylor, and Christopher J. Boreham. "GEOCHEMICAL TOOLS FOR EVALUATING PETROLEUM GENERATION IN MIDDLE PROTEROZOIC SEDIMENTS OF THE McARTHUR BASIN, NORTHERN TERRITORY, AUSTRALIA." APPEA Journal 34, no. 1 (1994): 692. http://dx.doi.org/10.1071/aj93051.

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Maturation parameters based on aromatic hydrocarbons, and particularly the methyl-phenanthrene index (MPI-1), are powerful indicators which can be used to define the oil window in Proterozoic and Early Palaeozoic petroleum source rocks and to compare maturities and detect migration in very old oils . The conventional vitrinite reflectance yardstick for maturity is not readily translated to these ancient sediments because they predate the evolution of the land plant precursors to vitrinite. While whole-rock geochemical tools such as Rock-Eval and TOC are useful for evaluation of petroleum potential, they can be imprecise when applied to maturity assessments.In this study, we carried out a range of detailed geochemical analyses on McArthur Basin boreholes penetrating the Roper Group source rocks. We determined the depth profiles for hydrocarbon generation based on Rock-Eval analysis of whole-rock, solvent-extracted rock, kerogen elemental H/C ratio and pyrolysis GC. Although we found that Hydrogen Index (HI) and the Tmax parameter were strongly correlated with other maturation indicators, they were not sufficiently sensitive nor were they universally applicable. Maturation measurements based on saturated biomarkers were not useful either because of the low abundance of these compounds in most Roper Group bitumens and oils.

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Kurovets, S. S., and І. V. Artym. "Evaluation of the geological factors impact on capacity and filtration properties of terrigenuous reservoirs of the Pre-Carpathian foredeep." Scientific Bulletin of Ivano-Frankivsk National Technical University of Oil and Gas, no. 1(44) (May 5, 2018): 25–37. http://dx.doi.org/10.31471/1993-9965-2018-1(44)-25-37.

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The following main geological factors that determine the reservoir properties of the terrigenous rocks of the Pre-Carpathian foredeep were identified, namely: mineral composition, structural and texture features, and thermobaric factors. The mineral composition of the rock-forming minerals, the shape, the size of the fragmented grains and pores, their mutual placement, the type of fluid and the thermodynamic state determine the reservoir properties of terrigenous rocks. The best reservoirs are sandstones, compiled with larger and sorted grains. The increase of clay and carbonate material sharply worsens the reservoir properties of rocks. Sealing and secondary processes (sieving, calcifying, pyrolysis) negatively affect the reservoir properties of rocks, reduce their porosity and permeability. Some dependencies were identified. These dependencies make it possible to predict the maximum porosity of sandstones, depending on their immersion in depth. The given porosity data of sandy-clayey rocks shows, that sorted quartz sandstones with insignificant contents of clayey and carbonate materials have greater intergranular porosity and permeability at great depths.

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Frantisek, Buzek, Gerslova Eva, Gersl Milan, Cejkova Bohuslava, Jackova Ivana, and Lnenickova Zdena. "Evaluation of the Gas Content in Archived Shale Samples: A Carbon Isotope Study." Geosciences 9, no. 11 (November 15, 2019): 481. http://dx.doi.org/10.3390/geosciences9110481.

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We examined 14 archived samples of shale for the chemical and 13C isotopic composition of residual gases produced as part of rock-crushing operations at a hammer mill. Results were compared with data on maturity from Rock-Eval pyrolysis and vitrinite reflectance measurements. The samples originated from three different formations (Mikulov Marls, Ostrava Formation, and Liteň Formation) located in the Czech Republic. For comparison, we examined a gas-prone shale sample from the Polish Silurian. We used changes in the chemical and isotopic composition of released gases to evaluate the isotope fractionation during gas loss and retroactively calculated the initial content of gas in the shale samples. The gas content estimates (in L of gas per ton of rock) correspond with the maturity parameters of the shales. Calculated isotope fractionation for the gas release was −3‰ for both methane and ethane. The archived samples primarily lost methane (up to 90%), with subsequent changes in the content of ethane and higher hydrocarbon levels.

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Bulatov, Timur, Elena Kozlova, Evgeniya Leushina, Ivan Panchenko, Natalia Pronina, Andrey Voropaev, Nikita Morozov, and Mikhail Spasennykh. "Alginite-Rich Layers in the Bazhenov Deposits of Western Siberia." Geosciences 11, no. 6 (June 11, 2021): 252. http://dx.doi.org/10.3390/geosciences11060252.

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In this study, we identified the luminescent layers containing a significant amount of alginite in the Upper Jurassic–Lower Cretaceous Bazhenov Formation named “the alginite-rich layers”. Lithological and geochemical methods were used to determine distinctive features of these layers and to evaluate their impact on the total petroleum generation potential of the Bazhenov Formation. We have shown that the composition of the alginite-rich layers differs significantly from the organic-rich siliceous Bazhenov rocks. Rock-Eval pyrolysis, bulk kinetics of thermal decomposition, elemental analysis, and the composition of pyrolysis products indicate type I kerogen to be the predominant component of the organic matter (OM). Isotope composition of carbon, nitrogen, and sulfur was used to provide insights into their origin and formation pathways. The luminescent alginite-rich layers proved to be good regional stratigraphic markers of the Bazhenov Formation due to widespread distribution over the central part of Western Siberia. They can also be applied for maturity evaluation of the deposits from immature to middle of the oil window, since the luminescence of the layers changes the color and intensity during maturation.

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Edilbi, Ayad N. F., Kamal Kolo, Blind F. Khalid, Mardin N. Muhammad Salim, Sana A. Hamad, and Shahang A. Ahmad. "Source Rock Evaluation of the Upper Triassic Baluti Formation in Bekhme-1 and Gulak-1 Wells from Akri-Bijeel Block, Kurdistan-Iraq." UKH Journal of Science and Engineering 5, no. 1 (June 30, 2021): 50–59. http://dx.doi.org/10.25079/ukhjse.v5n1y2021.pp50-59.

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This study reports on the petroleum potential of the Upper Triassic Baluti Formation in Bekhme-1 and Gulak-1 Wells from Akri¬-Bijeel Block within the Bekhme Anticline area, North of Erbil City. The area is a part of the Zagros Fold and Thrust Belt, and is locally situated within the High Folded Zone. Typically, the Baluti Formation is composed of gray and green shale calcareous dolomite with intercalations of thinly bedded dolomites, dolomitic limestones, and silicified limestones which in places are brecciated. The geochemical indicators obtained from Rock-Eval pyrolysis of Baluti samples gave Total Organic Carbon content (TOC wt. %) average values of 0.15 and 0.18 wt. % and potential hydrocarbon content (S2) average values of 0.78 mg HC/g rock and 0.58 mg HC/g rock for Bekhme-1 and Gulak-1 respectively, suggesting a source rock of poor potential. The type of organic matter is of mixed type II-III and III kerogens with an average Tmax value of 440 °C for both boreholes, exhibiting early to peak stage of thermal maturity. Considering the results of this study, it is concluded that Baluti Formation in the studied area can not be regarded as a potential source rock for hydrocarbon generation.

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Hackley, Paul C., Lixia Zhang, and Tongwei Zhang. "Organic petrology of peak oil maturity Triassic Yanchang Formation lacustrine mudrocks, Ordos Basin, China." Interpretation 5, no. 2 (May 31, 2017): SF211—SF223. http://dx.doi.org/10.1190/int-2016-0111.1.

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An organic petrology evaluation and a determination of solid bitumen reflectance [Formula: see text] were completed for organic-rich Triassic Yanchang Formation mudrocks ([Formula: see text]) from the Ordos Basin, north-central China, as part of a larger investigation of “shale gas” resources. These data were integrated with information from Rock-Eval programmed pyrolysis to show that the samples are in the peak oil window of thermal maturity and that organic matter is dominated by solid bitumen with minor amounts of type III kerogen (vitrinite and inertinite) from vascular land plants. Describing a “kerogen type” for these rocks based strictly on parameters determined from programmed pyrolysis is misleading because the original organic matter has converted to hydrocarbons (present as solid bitumen), a large proportion of which may have been expelled into adjacent reservoir facies. However, based on the comparison with immature-early mature lacustrine mudrock (Garden Gulch Member of Green River Formation) and marine shale (Boquillas Formation), we suggest that the original organic matter in the organic-rich samples examined for our study may have been type I/II kerogen with hydrogen index values of [Formula: see text] TOC.

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Khatibi, Seyedalireza, Mehdi Ostadhassan, David Tuschel, Thomas Gentzis, and Humberto Carvajal-Ortiz. "Evaluating Molecular Evolution of Kerogen by Raman Spectroscopy: Correlation with Optical Microscopy and Rock-Eval Pyrolysis." Energies 11, no. 6 (May 31, 2018): 1406. http://dx.doi.org/10.3390/en11061406.

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Vitrinite maturity and programmed pyrolysis are conventional methods to evaluate organic matter (OM) regarding its thermal maturity. Moreover, vitrinite reflectance analysis can be difficult if prepared samples have no primary vitrinite or dispersed widely. Raman spectroscopy is a nondestructive method that has been used in the last decade for maturity evaluation of organic matter by detecting structural transformations, however, it might suffer from fluorescence background in low mature samples. In this study, four samples of different maturities from both shale formations of Bakken (the upper and lower members) Formation were collected and analyzed with Rock-Eval (RE) and Raman spectroscopy. In the next step, portions of the same samples were then used for the isolation of kerogen and analyzed by Raman spectroscopy. Results showed that Raman spectroscopy, by detecting structural information of OM, could reflect thermal maturity parameters that were derived from programmed pyrolysis. Moreover, isolating kerogen will reduce the background noise (fluorescence) in the samples dramatically and yield a better spectrum. The study showed that thermal properties of OM could be precisely reflected in Raman signals.

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Pyliotis, I., E. Hamilaki, N. Pasadakis, and E. Manoutsoglou. "Comparative evaluation of Rock- Eval and elemental analysis to determine organic carbon content in sediment samples." Bulletin of the Geological Society of Greece 47, no. 2 (January 24, 2017): 862. http://dx.doi.org/10.12681/bgsg.11125.

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Rock-Eval and Elemental Analysis techniques are widely used in Organic Geochemistry for the determination of the organic content in sediment samples. Both techniques determine the carbon content using thermal treatment and pyrolysis and/or oxidation reactions. Due to the complex nature of the geochemical samples (different mineralogical composition, low organic carbon content, e.t.c) and the differences of their operational principles, disagreements are commonly observed between the analytical results of these techniques. In this work we studied in a systematic manner the performance of both techniques on a common sample set, consisting of immature, poor in organic carbon, sediments. It was demonstrated that both techniques applied on original and acid-treated samples, provide consistent analytical results for carbon content; that has also been showed by its mass-balance calculations showed.

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Ahmad, Sajjad, Faizan Ahmad, Abd Ullah, Muhammad Eisa, Farman Ullah, Khalid Kaif, and Suleman Khan. "Integration of the outcrop and subsurface geochemical data: implications for the hydrocarbon source rock evaluation in the Lower Indus Basin, Pakistan." Journal of Petroleum Exploration and Production Technology 9, no. 2 (October 25, 2018): 937–51. http://dx.doi.org/10.1007/s13202-018-0569-6.

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Abstract The present study details the hydrocarbon source rock geochemistry and organic petrography of the outcrop and subsurface samples of the Middle Jurassic Chiltan Formation and the Lower Cretaceous Sembar Formation from the Sann #1 well Central and Southern Indus Basin, Pakistan. The total organic carbon (TOC), Rock–Eval pyrolysis, vitrinite reflectance (Ro) % and Maceral analysis techniques were used and various geochemical plots were constructed to know the quality of source rock, type of kerogen, level of maturity and migration history of the hydrocarbons. The outcrop and Sann #1 well data on the Sembar Formation reveals poor, fair, good and very good quality of the TOC, type II–III kerogen, immature–mature organic matter and an indigenous hydrocarbon generation potential. The outcrop and Sann #1 well data on the Chiltan Formation show a poor–good quality of TOC, type II–III kerogen, immature–mature source rock quality and having an indigenous hydrocarbon generation potential. The vitrinite reflectance [Ro (%)] values and Maceral types [fluorescent amorphous organic matter, exinite, alginite and inertnite] demonstrate that maturity in both Sembar and the Chiltan formation at surface and subsurface fall in the oil and gas generation zone to cracking of oil to gas condensate zone. Recurrence of organic rich and poor intervals within the Sembar and Chiltan formation are controlled by the Late Jurassic thermal uplift preceding the Indo-Madagascar separation from the Afro-Arabian Plate and Early Cretaceous local transgressive–regressive cycles. From the current study, it is concluded that both Sembar and Chiltan formation can act as a potential hydrocarbon source rock in the study area.

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Bogdanovich, Natalia, Elena Kozlova, and Tagir Karamov. "Lithological and Geochemical Heterogeneity of the Organo-Mineral Matrix in Carbonate-Rich Shales." Geosciences 11, no. 7 (July 16, 2021): 295. http://dx.doi.org/10.3390/geosciences11070295.

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The paper discusses the issues of interaction of the organic matter and the siliceous-carbonate mineral matrix in unconventional reservoirs of the Upper Devonian Domanik Formation of the Upper Kama Depression of the Volga-Ural Basin. The Domanik Formation is composed of organic-rich low-permeability rocks. Lithological and geochemical peculiarities of rocks were studied using light microscopy, X-ray diffraction analysis (XRD), scanning electronic microscopy (SEM), and evaporation method. Organic matter was examined by the Rock-Eval pyrolysis with quantitative and qualitative evaluation of generation potential and maturity degree. Integrated analysis of results of lithological and geochemical studies allowed identifying intervals in the studied section where organic matter can form a complex association with the siliceous-carbonate matrix. It was fixed experimentally that in some cases the mineral carbonate matrix and the organic matter form a one-whole high-molecular compound. The authors supposed that in the course of sedimentation, organic matter is immobilized into the structure of the mineral carbonate matrix. At the deposition and diagenesis stage, the carbonate matter interacts with acids of the organic matter and forms natural organo-mineral polymers. Special physicochemical properties of such organo-mineral associations shed new light onto the problems of producing from hard-to-develop nonconventional carbonate reservoirs and evaluating the associated risks.

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Johannes, Ille, Kristjan Kruusement, and Rein Veski. "Evaluation of oil potential and pyrolysis kinetics of renewable fuel and shale samples by Rock-Eval analyzer." Journal of Analytical and Applied Pyrolysis 79, no. 1-2 (May 2007): 183–90. http://dx.doi.org/10.1016/j.jaap.2006.12.001.

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Liu, Bao Ping. "The Lateral Coring Data of Fine Layering Water Injection in the Development Area of Xingnan." Advanced Materials Research 962-965 (June 2014): 305–8. http://dx.doi.org/10.4028/www.scientific.net/amr.962-965.305.

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Daqing Oilfield has entered the high water cut development period, inter-plane layers, the inner layer of contradiction, multi-well, multi-layer high water, the remaining oil is highly fragmented. To mitigate the production decline, the need for sophisticated test stratified water injection technology, give full play to the advantages of each technology, and effective control of the natural decline rate and an average annual rate of increase water effectively tap the potential of residual oil. Use coring technology, rock pyrolysis technique, interpretation and evaluation method for logging flooded layer chromatography and saturated hydrocarbon fluorescence microscopy imaging technology created by the impact of a small reservoir heterogeneity can be intuitive, accurate evaluation of the remaining oil, applied sidewall coring data injection wells can profile, low oil shutoff and potential aquifer fracturing provide a strong basis.

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Khorasani, Ganjavar Khavari. "RECENT ORGANIC GEOCHEMICAL EVALUATION OF THE CENTRAL EROMANGA BASIN." APPEA Journal 27, no. 1 (1987): 106. http://dx.doi.org/10.1071/aj86011.

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Systematic analyses of bulk properties and of molecular composition, by gas chromatography (GC), fluorescence spectroscopy, gas chromatography-mass spectroscopy (GC-MS), reflectance photometry and 'Rock-Eval' pyrolysis of core samples from three stratigraphic bores from the central and northern-central Eromanga Basin, reveal the following:The organic facies variations in the central Eromanga are considerable; however, the biofacies can be grouped into three major types.The sediments do not enter the mature zone of oil generation until a reflectance level of 0.65 per cent Rv max. or higher is reached. The Birkhead Formation, with a 'hydrogen-rich' type III kerogen, is only marginally mature and the amounts of hydrocarbons already generated are minor. In the Early Jurassic sedimentary unit (Basal Jurassic Shale Unit), however, there is a distinct increase in the level of S1/Organic Carbon indices and in the maturity of organic matter. While the extracts from younger Jurassic sequences of the basin display a substantial waxy character, the bitumens derived from the Basal Jurassic Unit are highly aromatic in character and contain few saturated hydrocarbons.

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Rahmani, Khoshnoodkia, Kadkhodaie, Beiranvand Pour, and Tsegab. "Geochemical Analysis for Determining Total Organic Carbon Content Based on ∆LogR Technique in the South Pars Field." Minerals 9, no. 12 (November 28, 2019): 735. http://dx.doi.org/10.3390/min9120735.

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There is a recognized need for the determination of total organic carbon (TOC) as an essential factor in the evaluation of source rocks. In this study, the ∆LogR technique was coupled with logging curves of sonic, resistivity, spectral gamma-ray (SGR), and computed gamma-ray (CGR) to determine an accurate content of TOC in the Gadvan Formation. Multiple linear regression analysis was also applied to the ∆LogR technique. To this aim, 14 samples of the Gadvan Formation were taken from Wells B and C in the South Pars field and analyzed using Rock-Eval pyrolysis. Results from the ∆LogR technique and multiple linear regression analysis, well logs, and Rock-Eval were compared to calculate the accurate content of TOC in the Gadvan Formation. Geochemical data confirmed that the Gadvan Formation was a relatively poor source rock in the South Pars field, as average TOC and Tmax values of the samples were 0.79 and less than 430 °C, respectively. Also, the content of potassium (K < 0.1%) confirmed the origin of the source rock as a pure carbonate, whereas the low content of thorium (Th < 5 ppm) was indicative of the percentage of clays. There was a moderate content of uranium (U < 10 ppm), suggesting that the Gadvan Formation was not deposited in an excellent reducing environment to conserve the organic matter. Moreover, the results from the integration of the multiple linear regression model with SGR and CGR showed that the value of R2 was higher than the results obtained without SGR and CGR. Findings from this study could help the exploration and production team to determine the accurate content of TOC using the ∆LogR technique in association with logging curves.

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Alizadeh, Bahram, Amir Abbas Jahangard, Majid Alipour, and Ahmadreza Gandomi Sani. "Geochemical evaluation of Khami Group oils in the South Dezful Embayment, Iran." Journal of Petroleum Exploration and Production Technology 10, no. 8 (September 10, 2020): 3241–54. http://dx.doi.org/10.1007/s13202-020-00894-5.

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Abstract An integrated geochemical study, including GC, GC–MS and stable carbon isotope analyses, was conducted on a suite of oil samples from the Khami Group reservoirs to provide new insights into the Upper Jurassic–Lower Cretaceous petroleum system in the South Dezful Embayment. Possible source rocks were also characterized using Rock–Eval pyrolysis to address the likely potential source rocks. The oil samples representing four major reservoirs (Surmeh, Fahliyan, Gadvan and Dariyan) constitute a single genetic oil family according to bulk and biomarker parameters. High API (> 38°), highly saturated hydrocarbons (Sat > 65%), very low asphaltene content (Asp < 2%) and raised saturates/aromatics ratio (Sat/Aro > 2) are the bulk diagnostic characteristics of the studied oils implying more dominant terrigenous nature of the precursor organic matter. The predominance of C29 regular steranes (~ 40%), presence of C29Ts as well as very low gammacerane (< 10%) and moderate C35/C34 homohopane (< 1) are consistent with the mixed marine–terrigenous dysoxic organic matter input. The oils are assumed to be originated from Early Cretaceous source rocks at the peak of the oil generation window in a kitchen area located to the south of the studied region (i.e., the Binak–Borazjan Trough). The hydrocarbons were migrated from this kitchen to the structurally shallow-seated reservoirs in the center and west of the Kharg-Mish local paleo-high. The Khami Group reservoirs are not effectively sealed by the thin Hith anhydrites, and the Kazhdumi Formation finally trapped the migrated hydrocarbons. This study improves our knowledge regarding one of the active petroleum systems in the South Dezful Embayment, enhancing petroleum exploration success by navigating further drillings into the more prosperous targets.

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Chen, Junqing, Xingang Zhang, Zhuoheng Chen, Xiongqi Pang, Haijun Yang, Zhengfu Zhao, Bo Pang, and Kuiyou Ma. "Hydrocarbon expulsion evaluation based on pyrolysis Rock-Eval data: Implications for Ordovician carbonates exploration in the Tabei Uplift, Tarim." Journal of Petroleum Science and Engineering 196 (January 2021): 107614. http://dx.doi.org/10.1016/j.petrol.2020.107614.

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Altowairqi, Yazeed, Reza Rezaee, and Milovan Urosevic. "Quantitative application of post-stack inversion of organic-rich shale based on rock physics linear relationship and 3D seismic data, Perth Basin, Western Australia." APPEA Journal 54, no. 2 (2014): 532. http://dx.doi.org/10.1071/aj13105.

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Unconventional resources such as shale gas have been an extremely important exploration and production target. To understand the seismic responses of the shale gas plays, the use of rock physical relationship is important, which is constrained with geology and formation-evaluation analysis. Since organic-rich shale seismic properties remains poorly understood, seismic inversion can be used to identify the organic-rich shale from barren shale. This approach helps identify and map spatial distributions and of the organic rich shales. This study shows the acoustic impedance (AI), which is the product of compressional velocity and density, decreases nonlinearly with increasing total organic carbon (TOC) content. TOC is obtained using Roc-Eval pyrolysis for more than 120 core shale samples for the Perth Basin. By converting the AI data to TOC precent on the seismic data, we therefore can map lateral distribution, thickness, and variation in TOC profile. This extended abstract presents a case study of the northern Perth Basin 3D seismic with application of different approaches of seismic inversion and multi-attribute analysis with the rock physical relationships.

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Khatibi, Seyedalireza, Arash Abarghani, Kouqi Liu, Alexandra Guedes, Bruno Valentim, and Mehdi Ostadhassan. "Backtracking to Parent Maceral from Produced Bitumen with Raman Spectroscopy." Minerals 10, no. 8 (July 30, 2020): 679. http://dx.doi.org/10.3390/min10080679.

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In order to assess a source rock for economical exploitation purposes, many parameters should be considered; regarding the geochemical aspects, the most important ones are the amount of organic matter (OM) and its quality. Quality refers to the thermal maturity level and the type of OM from which it was formed. The origin of the OM affects the ability of the deposited OM between sediments to generate oil, gas, or both with particular potential after going through thermal maturation. Vitrinite reflectance and programmed pyrolysis (for instance, Rock-Eval) are common methods for evaluating the thermal maturity of the OM and its potential to generate petroleum, but they do not provide us with answers to what extent solid bitumen is oil-prone or gas-prone, as they are bulk geochemical methods. In the present study, Raman spectroscopy (RS), as a powerful tool for studying carbonaceous materials and organic matter, was conducted on shale and coal samples and their individual macerals to show the potential of this technique in kerogen typing and to reveal the parent maceral of the examined bitumen. The proposed methodology, by exhibiting the chemical structure of different organic matters as a major secondary product in unconventional reservoirs, can also detect the behavior of solid bitumen and its hydrocarbon production potential for more accurate petroleum system evaluation.

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Green, Hunter, Branimir Šegvić, Giovanni Zanoni, Silvia Omodeo-Salé, and Thierry Adatte. "Evaluation of Shale Source Rocks and Clay Mineral Diagenesis in the Permian Basin, USA: Inferences on Basin Thermal Maturity and Source Rock Potential." Geosciences 10, no. 10 (September 23, 2020): 381. http://dx.doi.org/10.3390/geosciences10100381.

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The use of mineral diagenetic indices and organic matter maturity is useful for reconstructing the evolution of sedimentary basins and critical assessments for potential source rocks for petroleum exploration. In this study, the relationship of clay mineral diagenesis and organic matter thermal indices (Rock-Eval Tmax) and calculated vitrinite reflectance (%Ro) were used to constrain the maximum burial depths and temperatures of three distinct intervals within the northern Permian Basin, USA. X-ray diffraction of clay fractions (<2 µm) consists of illite, chlorite, and illite-smectite intermediates. Primary clay mineral diagenetic changes progressively increase in ordering from R0 to R1 I-S between 2359.5 and 2485.9 m and the appearance of chlorite at 2338.7 m. Rock-Eval pyrolysis data show 0 to 14 wt% TOC, HI values of 40 to 520 mgHC/g TOC, and S2 values of 0 to 62 mg HC/g, with primarily type II kerogen with calculated %Ro within the early to peak oil maturation window. Evaluation of the potential for oil generation is relatively good throughout the Tonya 401 and JP Chilton wells. Organic maturation indices (Tmax, %Ro) and peak burial temperatures correlate well with clay mineral diagenesis (R0–R1 I-S), indicating that maximum burial depths and temperatures were between 2.5 and 4 km and <100 °C and 140 °C, respectively. Additionally, the use of clay mineral-derived temperatures provides insight into discrepancies between several calculated %Ro equations and thus should be further investigated for use in the Permian Basin. Accordingly, these findings show that clay mineral diagenesis, combined with other paleothermal proxies, can considerably improve the understanding of the complex burial history of the Permian Basin in the context of the evolution of the southern margin of Laurentia.

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Liu, Bo, Liangwen Yao, Xiaofei Fu, Bo He, and Longhui Bai. "Application of the Fractal Method to the Characterization of Organic Heterogeneities in Shales and Exploration Evaluation of Shale Oil." Journal of Marine Science and Engineering 7, no. 4 (March 28, 2019): 88. http://dx.doi.org/10.3390/jmse7040088.

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The first member of the Qingshankou Formation, in the Gulong Sag in the northern part of the Songliao Basin, has become an important target for unconventional hydrocarbon exploration. The organic-rich shale within this formation not only provides favorable hydrocarbon source rocks for conventional reservoirs, but also has excellent potential for shale oil exploration due to its thickness, abundant organic matter, the overall mature oil generation state, high hydrocarbon retention, and commonly existing overpressure. Geochemical analyses of the total organic carbon content (TOC) and rock pyrolysis evaluation (Rock-Eval) have allowed for the quantitative evaluation of the organic matter in the shale. However, the organic matter exhibits a highly heterogeneous spatial distribution and its magnitude varies even at the millimeter scale. In addition, quantification of the TOC distribution is significant to the evaluation of shale reservoirs and the estimation of shale oil resources. In this study, well log data was calibrated using the measured TOC of core samples collected from 11 boreholes in the study area; the continuous TOC distribution within the target zone was obtained using the △logR method; the organic heterogeneity of the shale was characterized using multiple fractal models, including the box-counting dimension (Bd), the power law, and the Hurst exponent models. According to the fractal dimension (D) calculation, the vertical distribution of the TOC was extremely homogeneous. The power law calculation indicates that the vertical distribution of the TOC in the first member of the Qingshankou Formation is multi-fractal and highly heterogeneous. The Hurst exponent varies between 0.23 and 0.49. The lower values indicate higher continuity and enrichment of organic matter, while the higher values suggest a more heterogeneous organic matter distribution. Using the average TOC, coefficient of variation (CV), Bd, D, inflection point, and the Hurst exponent as independent variables, the interpolation prediction method was used to evaluate the exploration potential of the study area. The results indicate that the areas containing boreholes B, C, D, F, and I in the western part of the Gulong Sag are the most promising potential exploration areas. In conclusion, the findings of this study are of significant value in predicting favorable exploration zones for unconventional reservoirs.

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Mamaseni, Wrya. "PETROLEUM POTENTIALITY AND PETROPHYSICAL EVALUATION OF THE MIDDLE-JURASSIC SARGELU FORMATION, NORTHERN IRAQ." Iraqi Geological Journal 53, no. 2D (October 31, 2020): 77–93. http://dx.doi.org/10.46717/igj.53.2d.6ms-2020-10-28.

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This study indicates the source rock evaluation and reservoir properties of the Middle-Jurassic Sargelu Formation in two selected sections (well Atrush-3 and Warte outcrop) northern Iraq. The well log data display that the shale includes 30% of the upper part of the Sargelu Formation. This extraordinary ratio of shale content has negative impacts on the reservoir properties in this part of the formation. The lower part of the formation has a good porosity ratio that reaches 15% as calculated from the log data. The porosity is obtained from analyzed core samples support the same conclusion that obtained in the log data analysis and it is measured at 9-17.5% for interval 1282-1301 m in Atrush-3 well and 5-7.9% in the interval 54-75 m Warte section. The formation has very good organic matter quality for black shales as the average total organic carbon (TOC) measured from the pyrolysis assessments is about 2.61 wt% in both the well and the section. The low oxygen index (average 26 mg CO2/g TOC) and high hydrogen index (average 423 mg HC/g TOC) indicate the variation of the kerogen class from type II in the Atrush-3 to type II-III in the Warte section. These two forms of kerogen can produce oil and condensate gas in a suitable state. Pristine/phytane (Pr/Ph) ratios are less than one (0.67-0.83) and this reveals the anoxic condition for the formation. The colors of the palynomorphs in the examined samples under the microscope changes from yellowish brown to brown (TAI=+2, -3), and the average Tmax and vitrinite reflectance are 444 oC and 0.80, respectively. Sargelu Formation is located within the mature and oil window. This is also supported by the carbon preference index which is around one (average 0.98).

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Maleki, Ashkan, Mohammad Hossein Saberi, Seyed Ali Moallemi, and Mohammad Hassan Jazayeri. "Evaluation of hydrocarbon generation potential of source rock using two-dimensional modeling of sedimentary basin: a case study in North Dezful Embayment, Southwest Iran." Journal of Petroleum Exploration and Production Technology 11, no. 7 (June 10, 2021): 2861–76. http://dx.doi.org/10.1007/s13202-021-01202-5.

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AbstractEarly Cretaceous and Jurassic sequences in the southwestern Iran host some of the largest hydrocarbon reservoirs in the globe. This study is aimed at evaluating the maturity of hydrocarbon fluids, migration paths, and characteristics of Pabdeh, Kazhdumi, Garu and Sargelu source rocks in this region. For this purpose, 27 samples of Pabdeh and Kazhdumi Formations from wells in the northern part of Dezful Embayment were chemically evaluated by Rock–Eval pyrolysis. OpenFlow™ software was utilized to analyze the burial history, conduct 1D thermal modeling in four oilfields and perform 2D modeling on a section to estimate the maturity and extension of sediments. Results of the 1D modeling showed that the kerogens of Sargelu, Garu and Kazhdumi Formations were properly matured, leading to some hydrocarbon outflow, although the organic matter content of Pabdeh Formation was too immature to produce any hydrocarbon. Based on the plot of hydrogen index (HI) versus Tmax, it was found that the studied formations were dominated by type II kerogen and a mixed species of type II and type III kerogens. Results of the migration path modeling showed some leakage from the Kazhdumi Formation up to an overlying seal that prevented the hydrocarbons from seeping out to surface. The Early and Middle Cretaceous oil systems were found to be connected through geometrical features or faults, with the Kazhdumi Formation separating the two systems. The results further showed the migration of hydrocarbons, at a relatively high rate, into the Abadan Plate through the sub-Kazhdumi reservoirs.The Early and Middle Cretaceous petroleum systems were found to be connected through particular geometry features or possibly faults, with the two systems separated by Kazhdumi Formation. For most part, the intensity of the maturation processes was found to decrease from east to west of the study area.

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Borisova, Lyubov S., Alexander N. Fomin, and Ekaterina S. Yaroslavtseva. "Geochemical features of the organic matter from Jurassic sediments of the Nadym‑Taz interfluve." Georesursy 22, no. 3 (September 30, 2020): 21–27. http://dx.doi.org/10.18599/grs.2020.3.21-27.

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This paper deals with the evaluation of oil-generation potential derived from the geochemical data on deep-buried Jurassic sedimentary rocks of the Nadym-Taz interfluve being part of the West Siberian petroleum basin (PB). The study provides analysis of samples from ultra-deep and deep wells that penetrated the Mesozoic-Cenozoic sedimentary cover in the north of the central part of PB (En-Yakhinsky, Evo-Yakhinsky, Yarudeysky, Tyumensky areas, etc.). The research focuses on the insoluble organic matter (OM) from Upper, Middle and Lower Jurassic sediments (54 samples). A comprehensive study of the kerogen by elemental, isotope analyses and pyrolysis Rock-Eval allowed obtaining the data critical for determining the genetic type of OM, its thermal maturity and residual petroleum generating potential. Using the Surfer and Corel Draw software, schematic maps and diagrams of variations in the most informative (i.e. area-specific and depth-dependent) geochemical parameters of the kerogen on the studied area and also down the section (from the Upper to the Lower Jurassic) were constructed and analyzed. The obtained geochemical data indicate that in the Jurassic sediments of the Nadym-Tazovsky interfluve, the highest OM generation potential is found in the Bazhenov horizon, as well as in individual members of the Malyshevsky, Leontievsky, Sharapovsky and Kiterbyutsky horizons. Based upon the level of OM maturity in the Upper and Middle Jurassic sediments, deposits of mainly oil and fat gases could be preserved, and in the Lower Jurassic – deposits of fat and dry gases.

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Xianzheng, Zhao, Pu Xiugang, Jin Fengming, Han Wenzhong, Shi Zhannan, Zhang Wei, Dong Xiongying, Wang Hu, and Li Haodong. "Quantitative Method for Evaluating Shale Oil Resources Based on Movable Oil Content." Geofluids 2021 (May 17, 2021): 1–9. http://dx.doi.org/10.1155/2021/5554880.

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The light hydrocarbon content ( S 1 ) of shale oil is lost in aboveground experimental measurements, which do not accurately reflect actual underground light hydrocarbon content and cannot meet the demands of resource quantity calculation. Based on field and laboratory experimental data from the second member of the Kongdian Formation in the Cangdong Sag, Bohai Bay Basin, the retained oil and movable oil contents in shale were calculated using a mathematical formula, and the total resources were quantified. The correction coefficient of S 1 from pyrolysis and the adsorption of oil by the total organic carbon (TOC) were determined to be 1.25 and 100 mg/g, respectively. The calculated parameter movable oil content ( S movable ) and the corresponding calculation formula of S 1 are proposed. The lower limit of S 1 is 100 mg HC/g rock, the TOC content is 4 wt % and 6 wt %, and the corrected movable oil content of 3 mg/g and 6 mg/g, respectively, will be of great significance in shale oil geology and engineering. The optimal geological and engineering settings are divided into three categories and eight subcategories on the basis of these findings. Methods for evaluating total, movable, and recoverable oil resources from shale are discussed, which elucidate a new method for quantitative evaluation and ranking of shale oil resources. This approach is suitable for application in other shale oil exploration and development areas globally.

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Wang, Enze, Gang Chen, Hanqi Li, Yanchen Song, Jianwei Wang, Zhuoya Wu, and Yue Feng. "Pore Structure, Fractal Features, and Oil Content Evaluation of Lacustrine Shale: A Case Study of First Member of Paleogene Shahejie Formation, NE China." Geofluids 2021 (September 23, 2021): 1–16. http://dx.doi.org/10.1155/2021/2721088.

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The complex and heterogeneous pore structure and oil content of lacustrine shales introduce significant challenges in the exploration of shale petroleum systems. To further expand our geological understanding of lacustrine shales and provide guidance for hydrocarbon exploration, in this study, based on programmed and improved Rock-Eval pyrolysis, total organic content (TOC) measurements, scanning electron microscopy (SEM) observations, and N2 adsorption (NA) experiments, a systematic evaluation of the mineral composition, geochemical features, pore structure, and oil contents of the third member of the Paleogene Shahejie Formation (Es3) shale in the typical lacustrine hydrocarbon enrichment sag (Nanpu Sag, Bohai Bay Basin) is conducted. The fractal theory is selected to quantify the pore system’s heterogeneity; also, the relationships between the pore structure parameters and the oil contents and mineral composition are revealed. Our results reveal the geochemical features of the Es3 shale are excellent, and thus, they can be classified as a set of high-quality source rocks (average TOC of 4.2%, mainly type II kerogen, and in the mature stage). Based on the SEM and NA analyses, the intercrystalline pores dominate the pore system. Moreover, the mesopores contribute the most specific surface area (SA) and pore volume (PV) to the samples (average contribution rates of 74.7 and 75.0%, respectively). The fractal dimensions have relatively strong positive correlations with PV and SA, which means more heterogeneous and complex pore structures provide more storage space and adsorption sites for shale oil accumulation. The clay mineral content is the most important factor which controls the pore structure parameter, and high clay content indicates high SA and PV. According to proposed numerical movable and adsorption hydrocarbon calculation models, the TOC content is the dominant factor controlling the movable and adsorption oil contents, but other factors’ impact also cannot be ignored. Our study not only provides guidance for shale oil exploration in the study area but also broadens our understanding of the oil contents of lacustrine shale.

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Luo, Long, Dongping Tan, Xiaojun Zha, Xianfeng Tan, Jing Bai, Cong Zhang, Jia Wang, Lei Zhang, and Xuanbo Gao. "Enrichment Factors and Resource Potential Evaluation of Qingshankou Formation Lacustrine Shale Oil in the Southern Songliao Basin, NE China." Geofluids 2021 (January 27, 2021): 1–20. http://dx.doi.org/10.1155/2021/6645467.

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China shale oil, which is preserved in lacustrine shale with strong heterogeneity and relatively low maturity, has been a research hotspot of unconventional resources. However, controlling factors of shale oil enrichment and resource potential evaluation restricted efficient exploration and development of lacustrine shale oil. On the basis of well logging data, TOC content, Rock-Eval pyrolysis values, thermal maturity, 100 oil saturation data, and pressure coefficient, the core observation, X-ray diffraction analysis, physical property analysis, scanning electron microscopy, CT scan, well logging interpretation, and volumetric genesis method depending on three-dimensional geological modeling were used to determine enrichment factors and evaluate the resource potential of Qingshankou Formation shale oil in the Southern Songliao Basin. Shale oil was mainly enriched in the semideep and deep lake shale of K2qn1, with the high capacity of hydrocarbon generation and favorable petrological and mineralogical characteristics, pore space characteristics, and physical properties in the low structural part of the Southern Songliao Basin. The three-dimensional geological resource model of Qingshankou Formation lacustrine shale oil was determined by the key parameters (Ro, TOC, and S 1 ) of shale oil in the favorable zone of the Southern Songliao Basin, northeast China. The geological resource of shale oil, which was calculated by two grid computing methods ( F 1 and F 2 ), was, respectively, 1.713 × 10 12 kg and 1.654 × 10 12 kg . The great shale oil resource indicates a promising future in the exploration and development of Qingshankou Formation shale oil of the Southern Songliao Basin.

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Cheng, Xiong, Dujie Hou, Xinhuai Zhou, Jinshui Liu, Hui Diao, and Lin Wei. "Geochemical Characterization of the Eocene Coal-Bearing Source Rocks, Xihu Sag, East China Sea Shelf Basin, China: Implications for Origin and Depositional Environment of Organic Matter and Hydrocarbon Potential." Minerals 11, no. 8 (August 23, 2021): 909. http://dx.doi.org/10.3390/min11080909.

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Eocene coal-bearing source rocks of the Pinghu Formation from the W-3 well in the western margin of the Xihu Sag, East China Sea Shelf Basin were analyzed using Rock-Eval pyrolysis and gas chromatography–mass spectrometry to investigate the samples’ source of organic matter, depositional environment, thermal maturity, and hydrocarbon generative potential. The distribution patterns of n-alkanes, isoprenoids and steranes, high Pr/Ph ratios, abundant diterpanes, and the presence of non-hopanoid triterpanes indicate predominant source input from higher land plants. The contribution of aquatic organic matter was occasionally slightly elevated probably due to a raised water table. High hopane/sterane ratios and the occurrence of bicyclic sesquiterpanes and A-ring degraded triterpanes suggest microbial activity and the input of microbial organisms. Overwhelming predominance of gymnosperm-derived diterpanes over angiosperm-derived triterpanes suggest a domination of gymnosperms over angiosperms in local palaeovegetation during the period of deposition. The high Pr/Ph ratios, the plot of Pr/n-C17 versus Ph/n-C18, the almost complete absence of gammacerane, and the distribution pattern of hopanes suggest that the samples were deposited in a relatively oxic environment. Generally, fluctuation of redox potential is coupled with source input, i.e., less oxic conditions were associated with more aquatic organic matter, suggesting an occasionally raised water table. Comprehensive maturity evaluation based on Ro, Tmax, and biomarker parameters shows that the samples constitute a natural maturation profile ranging from marginally mature to a near peak oil window. Hydrogen index and atomic H/C and O/C ratios of kerogens suggest that the samples mainly contain type II/III organic matter and could generate mixed oil and gas.

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Spigolon, André L. D., Michael D. Lewan, Henrique L. de Barros Penteado, Luiz Felipe C. Coutinho, and João G. Mendonça Filho. "Evaluation of the petroleum composition and quality with increasing thermal maturity as simulated by hydrous pyrolysis: A case study using a Brazilian source rock with Type I kerogen." Organic Geochemistry 83-84 (June 2015): 27–53. http://dx.doi.org/10.1016/j.orggeochem.2015.03.001.

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İnan, Sedat, and Hans J. Schenk. "Evaluation of petroleum generation and expulsion from a source rock by open and restricted system pyrolysis experiments. Part I. extrapolation of experimentally-derived kinetic parameters to natural systems." Journal of Analytical and Applied Pyrolysis 58-59 (April 2001): 213–28. http://dx.doi.org/10.1016/s0165-2370(00)00188-1.

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SHEKARIFARD, ALI, FRANÇOIS BAUDIN, KAZEM SEYED-EMAMI, JOHANN SCHNYDER, FATIMA LAGGOUN-DEFARGE, ARMELLE RIBOULLEAU, MARIE-FRANÇOISE BRUNET, and ALIREZA SHAHIDI. "Thermal maturity of the Upper Triassic–Middle Jurassic Shemshak Group (Alborz Range, Northern Iran) based on organic petrography, geochemistry and basin modelling: implications for source rock evaluation and petroleum exploration." Geological Magazine 149, no. 1 (March 9, 2011): 19–38. http://dx.doi.org/10.1017/s0016756811000161.

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AbstractOrganic petrography and geochemical analyses have been carried out on shales, carbonaceous shales and coals of the Shemshak Group (Upper Triassic–Middle Jurassic) from 15 localities along the Alborz Range of Northern Iran. Thermal maturity of organic matter (OM) has been investigated using vitrinite reflectance, Rock-Eval pyrolysis and elemental analysis of kerogen. Reflectance of autochthonous vitrinite varies from 0.6 to 2.2% indicating thermally early-mature to over-mature OM in the Shemshak Group, in agreement with other maturity parameters used. The shales of the Shemshak Group are characterized by poor to high residual organic carbon contents (0.13 to 5.84%) and the presence of hydrogen-depleted OM, predominantly as a consequence of oxidation of OM at the time of deposition and the hydrogen loss during petroleum generation. According to light-reflected microscopy results, vitrinite/vitrinite-like macerals are dominant in the kerogen concentrates from the shaly facies. The coals and carbonaceous shales of the Shemshak Group show a wide range in organic carbon concentration (3.5 to 88.6%) and composition (inertinite- and vitrinite-rich types), and thereby different petroleum potentials. Thermal modelling results suggest that low to moderate palaeo-heat flow, ranging from 47 to 79 mW m−2 (57 mW m−2 on average), affected the Central-Eastern Alborz basin during Tertiary time, the time of maximum burial of the Shemshak Group. The maximum temperature that induced OM maturation of the Shemshak Group seems to be related to its deep burial rather than to a very strong heat flow related to an uppermost Triassic–Liassic rifting. The interval of petroleum generation in the most deeply buried part of the Shemshak Group (i.e. Tazareh section) corresponds to Middle Jurassic–Early Cretaceous times. Exhumation of the Alborz Range during Late Neogene time, especially along the axis of the Central-Eastern Alborz, where maximum vitrinite reflectance values are recorded, probably destroyed possible petroleum accumulations. However, on the northern flank of the Central-Eastern Alborz, preservation of petroleum accumulations may be expected. The northern part of the basin therefore seems the best target for petroleum exploration.

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Erofeev, A. A., A. A. Pachezhercev, I. A. Karpov, N. V. Morozov, A. G. Kalmykov, A. N. Cheremisin, E. V. Kozlova, and A. Yu Bychkov. "Evaluation of the thermal effect potential for Bazhenov formation production stimulation based on the experimental data." Moscow University Bulletin. Series 4. Geology, no. 4 (August 28, 2017): 39–47. http://dx.doi.org/10.33623/0579-9406-2017-4-39-47.

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In this paper the temperature treatment impact on Bazhenov formation core samples are shown. Impact was performed by pyrolysis in a temperature range of 300-480 °C and in the closed autoclave in the presence of water at reservoir pressure. It is shown that as a result of thermal exposure at 400 °C pyrolytic peak S2 is reduced by 90-95% and generation potential of rocks almost completely implemented. The microtomographic samples studies combined with scanning electron microscopy allowed to establish the dependence of permeability and porosity of the rocks. It demonstrated that even at 350 °C the fracture system formed in core samples also the porosity and permeability due to impact may increase from several times to several ten times. The results will allow for a more accurate simulation of enhanced oil recovery treatment on Bazhenov formation rocks to increase oil recovery.

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Greenwood, P. F., and N. Sherwood. "A REVIEW: ORGANIC GEOCHEMICAL STUDIES BY LASER PYROLYSIS MASS–SPECTROMETRY AND HOW THEY COMPARE WITH FLASH PYROLYSIS MASS–SPECTROMETRY STUDIES." APPEA Journal 35, no. 1 (1995): 633. http://dx.doi.org/10.1071/aj94038.

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Various methods of laser pyrolysis have been used by researchers to investigate at a molecular level the chemistry of dispersed organic matter. An understanding of molecular composition is important for evaluations of oil generation potential and maturation levels of source rocks. Laser-based pyrolysis-mass spectrometry studies as applied to petroleum source rocks and coals are reviewed. Experiments undertaken to date involve three main techniques: (i) laser ionisation-mass spectrometry; (ii) laser pyrolysis-gas chromatography-mass spectrometry; and (iii) laser desorption-electron im-pact-mass spectrometry. These techniques have had variable degrees of success for detecting structurally significant hydrocarbon products. Typically assessed through comparison with conventional flash pyrolysis data, the relative merits of the different techniques are described.The most powerful analysis is obtained through the combined use of chromatographic separation and mass spectrometry. The emergence of the laser pyrolysis-gas chromatography-mass spectrometry technique offers enormous potential for various geochemical applications. Laser pyrolysis in conjunction with a microscope (micropyrolysis) allows analysis of specific organic entities, thereby avoiding the masking of individual properties through bulk analysis. However, laser micropyrolysis-gas chromatography-mass spectrometry has not been widely accepted because of the complexities inherent in interfacing the required hardware devices and the high cost of laser instruments compared with conventional pyrolysers. Chromatography also adds cost with regard to both instrumentation and analysis time. Unfortunately, the ability of laser ionisation to provide insights into molecular structure is severely limited by a predominance of carbon cluster ions from highly carbonaceous materials.In contrast, the laser desorption-electron impact ionisation routine yields large ion concentrations of aliphatic and aromatic products. Sufficient information has been obtained with this method to distinguish source rocks and coals of different organic composition.

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Liu, Peng, Xiaofeng Wang, Xiaofu Li, Ting Zhang, and Wenhui Liu. "Geochemical Characteristics of Released Organic Matters by Acid Decomposition of Hydrocarbon Source Rocks from Different Sedimentary Basins." Geofluids 2019 (December 10, 2019): 1–12. http://dx.doi.org/10.1155/2019/4816218.

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It has been acknowledged that carbonate was identified as the source rocks of a series of oil-gas fields worldwide. For evaluating the carbonate source rocks, total organic carbon (TOC) contents act as an important indicator. However, the acid solution, which has been generated during conventional TOC measurements, contain organic matters. Hence, the released organic matters in acid solution during carbonate decomposition may lead to underestimate the hydorcarbon generation potential. In this study, rock-eval pyrolysis technique was applied to bulk rock and residue after acid treatment. Meanwhile, the organic matters in acid solution were measured by Gas Chromatography-Mass Spectrometer (GC-MS) to investigate the geochemical characteristics. In addition, the hydrocarbon generation and alteration of TOC contents of released organic matters by acid treatment were studied by hydrous pyrolysis experiments. The results show that the acid solution contains organic compounds, including n-alkanes, saturated fatty acids and fatty acid methyl esters. Meanwhile, total organic carbon (TOC) contents and hydrocarbon generation potential (S1+S2) significantly decrease for bulk rocks after acid treatment in low maturity samples. Moreover, organic CO2 (S3) decreased after treating of acid, revealing that acidolysis process can affect and release organic matters containing oxygen-bearing functional groups. The S1, S2, S3, and TOC loss are positive correlation with the proportion of rock loss during acidolysis, indicating that the organic matters in acid solution are associated with carbonate minerals. The organic fractions may exist as adsorption state on the surface of carbonate minerals and (or) exist as organic acid salts. Moreover, the thermal simulation experiments reveal that the organic matter in acid solution, which is not recovered by the conventional measurement approach, could contribute to hydrocarbon generation.

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Lillack, H., and K. Schwochau. "Kinetic evaluations of individual hydrocarbon (C1C4) generation by nonisothermal source rock pyrolysis." Journal of Analytical and Applied Pyrolysis 28, no. 1 (February 1994): 121–36. http://dx.doi.org/10.1016/0165-2370(93)00761-b.

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Zhao, Wenzhi, Shuichang Zhang, Bin Zhang, Kun He, and Xiaomei Wang. "New Insight into the Kinetics of Deep Liquid Hydrocarbon Cracking and Its Significance." Geofluids 2017 (2017): 1–11. http://dx.doi.org/10.1155/2017/6340986.

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The deep marine natural gas accumulations in China are mainly derived from the cracking of liquid hydrocarbons with different occurrence states. Besides accumulated oil in reservoir, the dispersed liquid hydrocarbon in and outside source also is important source for cracking gas generation or relayed gas generation in deep formations. In this study, nonisothermal gold tube pyrolysis and numerical calculations as well as geochemical analysis were conducted to ascertain the expulsion efficiency of source rocks and the kinetics for oil cracking. By determination of light liquid hydrocarbons and numerical calculations, it is concluded that the residual bitumen or hydrocarbons within source rocks can occupy about 50 wt.% of total oil generated at oil generation peak. This implies that considerable amounts of natural gas can be derived from residual hydrocarbon cracking and contribute significantly to the accumulation of shale gas. Based on pyrolysis experiments and kinetic calculations, we established a model for the cracking of oil and its different components. In addition, a quantitative gas generation model was also established to address the contribution of the cracking of residual oil and expulsed oil for natural gas accumulations in deep formations. These models may provide us with guidance for gas resource evaluation and future gas exploration in deep formations.

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Marshall, Craig P., Michael A. Wilson, Birgitta Hartung-Kagi, and Gwenda Hart. "Potential of emission Fourier transform infrared spectroscopy for in situ evaluation of kerogen in source rocks during pyrolysis." Chemical Geology 175, no. 3-4 (June 2001): 623–33. http://dx.doi.org/10.1016/s0009-2541(00)00383-1.

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Rooney, Alan D., David Selby, Michael D. Lewan, Paul G. Lillis, and Jean-Pierre Houzay. "Evaluating Re–Os systematics in organic-rich sedimentary rocks in response to petroleum generation using hydrous pyrolysis experiments." Geochimica et Cosmochimica Acta 77 (January 2012): 275–91. http://dx.doi.org/10.1016/j.gca.2011.11.006.

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Pan, Changchun, Min Zhang, Dehua Peng, Linping Yu, Jinzhong Liu, Guoying Sheng, and Jiamo Fu. "Confined pyrolysis of Tertiary lacustrine source rocks in the Western Qaidam Basin, Northwest China: Implications for generative potential and oil maturity evaluation." Applied Geochemistry 25, no. 2 (February 2010): 276–87. http://dx.doi.org/10.1016/j.apgeochem.2009.11.013.

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Yang, Jianguo, Liu Wang, Shichao Li, Cheng Zuo, Fei Xiao, Yuchu Chen, Yulai Yao, and Longhui Bai. "The Influence of Reservoir Composition on the Pore Structure of Continental Shale: A Case Study from the Qingshankou Formation in the Sanzhao Sag of Northern Songliao Basin, NE China." Geofluids 2021 (September 8, 2021): 1–21. http://dx.doi.org/10.1155/2021/5869911.

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Determining the pore structure characteristics and influencing factors of continental shale reservoir in the oil generation stage is of great significance for evaluating the shale oil reservoir space and analyzing shale oil enrichment mechanism. In this paper, shale from the first member of the Upper Cretaceous Qingshankou Formation (K2qn1) in the Songliao Basin was selected. X-ray diffraction (XRD), Rock-Eval pyrolysis, total organic carbon content (TOC), scanning electron microscopy (SEM), nitrogen gas adsorption (N2GA), and high-pressure mercury injection (HPMI) were used to clarify the composition characteristics of inorganic minerals and organic matter and determine the influencing factors of pore development in the K2qn1 shale. The results show that intergranular pores related to clay minerals and quartz, intragranular dissolution pores related to feldspar, and other mineral intragranular pores are developed. The organic matter pore is less developed, mainly composed of intragranular pores and crack pores of organic matter. Mesopores related to clay minerals are widely developed, rigid quartz particles can protect and support mesopores and macropores, and carbonate cementation can inhibit pore development. Although the TOC contents of shale are commonly less than 2.5%, it has a good positive correlation with porosity; TOC is greater than 2.5%, and the increase of residual oil fills part of the pores, leading to a decrease in porosity with the increase of TOC. Three types (types I, II, and III) of the reservoir space were classified by the combined pore size distribution diagram of N2GA and HPMI. By comparing the characteristics of pore structure parameters, it is found that Type I reservoir space is favorable for shale oil enrichment. It provides scientific guidance for shale oil exploration in the Songliao Basin.

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Moore, Shawn A., Lauren P. Birgenheier, Matthias D. Greb, Daniel Minisini, Maísa Tunik, and Julieta Omarini. "Facies heterogeneity and source potential of carbonate-mudstone-dominated distal ramp deposits, Agrio Formation, Neuquén Basin, Argentina." Journal of Sedimentary Research 90, no. 5 (May 7, 2020): 533–70. http://dx.doi.org/10.2110/jsr.2020.25.

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ABSTRACT The carbonate-mudstone-dominated Lower Cretaceous Agrio Formation is the youngest marine source rock of the hydrocarbon-prolific Neuquén Basin in Argentina, yet its facies variability and unconventional hydrocarbon potential remains relatively understudied. Detailed studies of mudstone facies variability in thick, carbonate mudstone successions deposited largely below storm wave base (i.e., chalk–marl, black shale, limestone), like the Agrio Formation, are rare and instead commonly focus on biostratigraphy or organic geochemistry alone. A continuous northern section of the Agrio Formation and a southern composite section of the lower Pilmatué and middle Avilé members, totaling ∼ 1,200 m of outcrop, were measured. From these measured sections, programmed pyrolysis (n = 339 samples), X-ray diffraction (XRD; n = 69), and thin sections (n = 69) were used to develop a high-resolution integrated macrofacies and microfacies scheme. The four most volumetrically abundant facies include detrital-quartz-silt-bearing fine mudstone (facies 1), radiolarian-bearing calcareous fine mudstone (facies 2), detrital-quartz-silt- and shell-bearing calcareous fine mudstone (facies 3), and calcareous wackestone (facies 4). All four facies are volumetrically dominated by carbonate mud matrix (i.e., micrite) that represents either 1) original pelagic coccolithophore deposition modified by diagenesis, 2) transported carbonate mud (i.e., bottom currents like contour currents or sediment gravity flows), or 3) a combination of both. Outcrop observations, XRD mineralogic trends, and petrographic variations in grain composition between detrital quartz silt, radiolarian and microfossil to macrofossil content (mainly benthic foraminifera and bivalves) distinguish the four mudstone facies. The facies scheme indicates distinctly more heterogeneous and current-influenced sedimentation in the downdip sub-storm wave base than previously described in the Agrio and in carbonate-dominated basinal settings in general. A depositional model is proposed for further testing that may prove valuable towards re-evaluating basinal carbonate mudstone successions worldwide. Utilizing TOC, S2, and HI value cutoffs, this study defines five discrete stratigraphic packages in the Agrio Formation that have the highest source potential, collectively totaling ∼ 140 m thick. The novel integration of macrofacies and microfacies analysis, stratigraphy, and a geochemical analysis allow both depositional insights and the assessment of a potential source rock. The study adds to a growing body of literature on 1) carbonate ramp (or slope) to basinal processes and 2) facies models for organic-rich, carbonate-dominated mudstone successions that are unconventional hydrocarbon systems.

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Zagnitko, V., and V. Mykhailov. "Ukraine's shale bearing strata gas: geochemical features." Visnyk of Taras Shevchenko National University of Kyiv. Geology, no. 1 (64) (2014): 11–18. http://dx.doi.org/10.17721/1728-2713.64.02.11-18.

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Relevance of research is caused by the need to expand the mineral and resource base of fuel and energy resources in Ukraine. The increasing demand for oil and natural gas, depletion of traditional deposits and rising prices cause the considerable interest in the search for hydrocarbon deposits of unconventional type, therefore the interest in studying of various aspects of oil and gas potential of shale strata of Ukraine is growing every year. An important argument in the development of search criteria and evaluation of unconventional hydrocarbon deposits is the study of their component composition and geochemical features. Among the natural gases of gas-bearing shale strata are often present: methane, nitrogen, carbon dioxide, heavy hydrocarbons (ethane, propane, pentane, hexane, butane), hydrogen, hydrogen sulfide, inert gases, and (very rarely) oxides of carbon, nitrogen, sulfur and others. The most common gas components are: methane, nitrogen, carbon dioxide and hydrogen. Formation of gases is associated with the geological history of the formation of separate areas. Therefore their genesis in different periods may be associated with both metamorphism of organic-containing strata, including coal strata, and with deep updrafts, resulting from endogenous causes (mainly due to the dynamics of tectonic development and differentiation of the Earth's geospheres), as well as provoked by external factors (including the fall of large celestial bodies). According to the pyrolysis of samples of shales and other compacted rocks the component composition of gases is defined as very uneven and is difficult to systematize and excretion patterns. In particular, due to the results of these analyzes we can state predominance of carbon dioxide and hydrogen in gases in almost all samples regardless of the lithology composition of host rocks. Some samples recorded high content of sulfurous gases, usually in rocks containing sulfides. Generally, methane content in the samples is less dependent on the content of it in the sequence, particularly in the mineral component of collectors it is also not high. The isotopic composition of carbon in the organic component of the samples is slightly enriched in the heavy isotope d13 (d13Ñ = -22-24‰) and some carbonates contain abnormal amounts of this isotope (d13Ñ to +15‰). For the formation of carbonates with this unusual isotopic composition are required unusual physical and chemical conditions of formation, in particular unbalanced conditions of isotopic fractionation resulting in systems supersaturated by hydrocarbons.

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Guha, Sonali, and K. N. Singh. "Source rock potentiality of Ib-Valley Coals, Mahanadi Coalfields Limited, Orissa, India." Journal of Nepal Geological Society 29 (October 2, 2004). http://dx.doi.org/10.3126/jngs.v29i0.31713.

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Rock eval pyrolysis is instrumental in rapid evaluation of maturation and source rock characteristics by providing vital information about the quantity, type and thermal maturity of organic matter. The Ib-Valley coal deposits have been characterized for their source rock potentiality and thus to explore the chances of their involvement in hydrocarbon generation.

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Journal articles on the topic 'Rock evaluation pyrolysis'

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