Vitrinite Reflectance Measurements Research Articles

Construct a Paleo-Limnological Environment Based on Coal Petrography; Case Study, Two Selected Coal Seams, North Crowsnest Open-Pit Mine, Canada

The Crowsnest coalfield is a separated structural coalfield at the East Kootenay basin within southeast British Columbia. Selected Jurassic-Cretaceous two coals seam S-10 and S-C of the Mist-Mountain formation were investigated from the points of coal petrography to construct a Paleo-limnological setting. Twenty-two channel coal samples were assembled and measured from S-10 and S-C coal seams. Vitrinite reflectance measuring of the S-10 coal concern to low-volatile bituminous (1.61, on average). While the vitrinite reflectance measurements of S-C coal seam show an average value of 0.98 related to high-volatile bituminous. Petrographic analysis demonstrates that the S-10 coal seam appears to be rich in inertinite than the S-C coal seam that appears rich in vitrinite. Applying coal facies indices of Tissue Preservation Index, Gelification Index, Ground Water Index Vegetation Index and coal facies diagrams for the studied coal seams aid to suggest a condition of the depositional Paleo-environments. The results promote Paleo-depositional sites of telmatic to limno-telmatic setting of rheotropic systems swamp. The obtained results show a trend of increase in both herbaceous flora and anoxic waterlogged limo-telmatic setting toward the younger coal seam S-C than the older S-10 coal seam.

Thermal Maturation Regime Revisited in the Dongying Depression, Bohai Bay Basin, East China

To the accurate reconstruction of the hydrocarbon generation history in the Dongying Depression, Bohai Bay Basin, East China, core samples of the Eocene Shahejie Formation from 3 shale oil boreholes were analyzed using organic petrology and organic geochemistry methods. The shales are enriched in organic matter with good to excellent hydrocarbon generation potential. The maturity indicated by measured vitrinite reflectance (%Ro) falls in the range of 0.5–0.9% and increases with burial depth in each well. Changes in biomarker and aromatic hydrocarbon isomer distributions and biomarker concentrations are also unequivocally correlated with the thermal maturity of the source rocks. Maturity/depth relationships for hopanes, steranes, and aromatic hydrocarbons, constructed from core data indicate different well locations, have different thermal regimes. A systematic variability of maturity with geographical position along the depression has been illustrated, which is a dependence on the distance to the Tanlu Fault. Higher thermal gradient at the southern side of the Dongying Depression results in the same maturity level at shallower depth compared to the northern side. The significant regional thermal regime change from south to north in the Dongying Depression may exert an important impact on the timing of hydrocarbon maturation and expulsion at different locations. Different exploration strategies should be employed accordingly.

Geochemical characteristics of natural gas in tight sandstone of the Chengdu large gas field, Western Sichuan Depression, Sichuan Basin, China

SINOPEC has made significant progress in natural gas exploration in terrigenous tight sandstone in the Western Sichuan Depression, making it one of the predominant exploration areas in the Sichuan Basin. Although the Chengdu large gas field was located in the main reservoirs of Upper Jurassic tight sandstone, few geochemical proofs were presented to support the explanation of the gas source, and regional differences in natural gas have been poorly investigated. The Jurassic tight gas in the Chengdu large gas field has a dryness coefficient (C1/C1-5) of 0.939–0.982, and the δ13C1, δ13C2, and δD1 values range from −33.7‰ to −30.7‰, −25.4‰ to −22.3‰, and −162‰ to −153‰, respectively, with positive carbon and hydrogen isotopic series of gaseous alkanes. The carbon and hydrogen isotopic compositions of the Jurassic tight gas indicate that it is typically coal-derived gas. The measured vitrinite reflectance (RO) values of source rocks of Member 5 of the Xujiahe Formation, which are demonstrated as the main source of Jurassic tight gas, are consistent with the calculated RO values according to the two-stage fractionation model of coal-derived gas. Effective source rocks are rare in the Lower Jurassic Baitianba Formation of the study area, which is considered to have only a minor contribution to the Jurassic gas reservoirs. The geochemical characteristics of Jurassic natural gas from various gas fields in the Western Sichuan Depression vary depending on the effect of different gas sources and accumulation processes.

Petrography, Mineralogy, and Geochemistry of Thermally Altered Coal in the Tashan Coal Mine, Datong Coalfield, China

A suite of coal samples near a diabase dike were collected to investigate the petrographic, mineralogical, and geochemical characteristics of thermally altered coal in Datong Coalfield, China. Proximate analysis, vitrinite reflectance measurement, and petrographic analysis were applied to identify and characterize the alteration halo; optical microscope observation, qualitative X-ray diffractometry, and SEM-EDS were applied to study the phases, occurrence, and composition of minerals; XRF, ICP-MS, and AFS were applied to determine concentrations of major and trace elements; and the occurrence modes of elements were studied by correlation and hierarchical cluster analysis as well as SEM-EDS. The results demonstrated that the 3.6 m dike has caused an alteration halo of approximately 2 m in diameter. In addition, the thermally altered coals were characterized by high vitrinite reflectance, low volatile matter, and the occurrence of thermally altered organic particles. Dolomite and ankerite in the thermally altered coal may be derived from hydrothermal fluids, while muscovite and tobelite may be transformed from a kaolinite precursor. The average concentration of Sr in the Tashan thermally altered coal reached 1714 μg/g, which is over 12 times that of the Chinese coal; the phosphate minerals and Sr-bearing kaolinite account for this significant enrichment. The cluster analysis classified elements with geochemical associations into four groups: group 1 and 2 were associated with aluminosilicates, clays, and carbonates and exhibited enrichment in the coal/rock contact zone, indicating that the dike may be the source of the elements; group 3 included P2O5, Sr, Ba, and Be, which fluctuate in coals, suggesting that their concentrations were influenced by multiple-factors; group 4 did not manifest obvious variations in coals, implying that the coal itself was the source.

O21 - Topic: AS02-Epidemiology: CONDITIONAL RELATIVE SURVIVAL IN MYELODYSPLASTIC SYNDROMES REVEALS A PERMANENT EXCESS MORTALITY RISK FOR LONG-TERM SURVIVORS: A POPULATION-BASED STUDY IN THE NETHERLANDS

SINOPEC has made significant progress in natural gas exploration in terrigenous tight sandstone in the Western Sichuan Depression, making it one of the predominant exploration areas in the Sichuan Basin. Although the Chengdu large gas field was located in the main reservoirs of Upper Jurassic tight sandstone, few geochemical proofs were presented to support the explanation of the gas source, and regional differences in natural gas have been poorly investigated. The Jurassic tight gas in the Chengdu large gas field has a dryness coefficient (C1/C1-5) of 0.939–0.982, and the δ13C1, δ13C2, and δD1 values range from −33.7‰ to −30.7‰, −25.4‰ to −22.3‰, and −162‰ to −153‰, respectively, with positive carbon and hydrogen isotopic series of gaseous alkanes. The carbon and hydrogen isotopic compositions of the Jurassic tight gas indicate that it is typically coal-derived gas. The measured vitrinite reflectance (RO) values of source rocks of Member 5 of the Xujiahe Formation, which are demonstrated as the main source of Jurassic tight gas, are consistent with the calculated RO values according to the two-stage fractionation model of coal-derived gas. Effective source rocks are rare in the Lower Jurassic Baitianba Formation of the study area, which is considered to have only a minor contribution to the Jurassic gas reservoirs. The geochemical characteristics of Jurassic natural gas from various gas fields in the Western Sichuan Depression vary depending on the effect of different gas sources and accumulation processes.

THE ZONATION OF COAL RANK IN MUARA ENIM FORMATION BASED ON THE REFLECTION STUDY

Coal is a sedimentary rock containing approximately 50% to 70% carbon derived from the accumulation of plant residue that had undergone chemical and physical changes. In this research, the petrographic analysis method of coal was conducted based on the following parameters, measuring vitrinite reflectance (Ro%), estimation of moisture, volatile matter, and carbon-hydrogen content. This study aims to determine the zonation of coal rank through the vitrinite reflectance analysis in Maura Enim Formation. The samples observed were obtained from the Muara Enim Formation, which had undergone certain geological events to form lignite and anthracite coal ranks, then analyzed using the descriptive method. The results showed that the reflectance value of vitrinite was between 0.20% - 0.44%, which was utilized in the sorting of coal from lignite - sub-bituminous, according to ASTM D2798-06 (2006). Furthermore, in the Southwest region, coal is formed through greater pressure than those in the Northeast. Generally, the level of difference is caused by pressure, temperature, and time factor. Therefore, this study is recommended as a guideline in determining coal rank through vitrinite reflectance analysis in different formations.

Modeling of the Petroleum System in the Cauvery Basin, Sri Lanka

A part of the southeastern onshore area of India and the northwestern onshore area of Sri Lanka, and the Palk Strait come under the Cauvery Basin. The Indian side of the Cauvery Basin has proven hydrocarbon reserves, while the Sri Lankan sector remains relatively under-explored. Only six exploration wells drilled in the Sri Lankan sector from 1972 to 1981 was dry. Since little further exploration has taken place from 1981 to this date, the existence of an active petroleum system in the Sri Lanka sector of the basin is not known. The objective of this study was to simulate the petroleum system in the Sri Lankan sector of the Cauvery Basin on Petromod 1D software (v.12.2) using data from unpublished reports and data in the public domain. The model was validated using the measured vitrinite reflectance data. Results of the study showed that Albian and Late Cretaceous shale in the Pesalai area have relatively higher hydrocarbon source potential and that hydrocarbon exploration in the Sri Lankan sector of the Cauvery Basin should mainly target Cretaceous and Eocene clastic and carbonate reservoirs associated with faults and anticlinal traps. Hydrocarbon potential in the Pesalai area is relatively higher than that in the Palk-Bay area.

Trapping of uranium by organic matter within sandstones during mineralization process: A case study from the Shuanglong uranium deposit, China

Carbonaceous debris (i.e., CD), dispersed organic matter (i.e., DOM) within sandstones, has been studied in the Shuanglong uranium deposit of the southern Ordos Basin, northern China. Relations of uranium enrichment and organic matter (i.e., OM) were investigated through maceral analyses, proximate analysis, vitrinite reflectance measurements, and morphology analyses of uranium minerals. The results show that CD widely distributed in sandstones, is associated with pyrite and uranium minerals. Macerals are mostly composed of telinite, collotelinite, collodetrinite, semifusinite, and inertodetrinite, including that collotelinite is dominant (contents more than 60%). The CD is at the stage of medium coalification, and is of low moisture, high ash, high volatile matter, medium fixed carbon, and high sulfur. Uranium occurs in uranium minerals (i.e., pitchblende and coffinite) and amorphous uranium. Moreover, uranium minerals partly or completely replace macerals. Statistical analyses show that porous inertinite and higher organic matter maturity is more advantageous to uranium enrichment. Additionally, uranium is unevenly distributed in macerals along certain directions, which is related to the physicochemical properties of macerals. Porous inertinite could provide channel for uranium-bearing fluid migration and space for uranium preconcentration. The CD at the stage of gas coal is of reducibility to be favorable for the forming of uranium minerals. Moreover, the relative atomic content of uranium (IV) increases with the increasing organic matter maturity. Uranium-bearing fluid could permeate into macerals under certain physical and chemical conditions, and react, i.e., adsorption followed by reduction. It is beneficial to comprehend the mechanism of uranium mineralization, providing certain guides for prospection.

Characteristics of “Guangyuan-Wangcang” trough during Late Middle Permian and its petroleum geological significance in northern Sichuan Basin, SW China

Based on outcrop characteristics, combined with regional tectonic background, drilling and geophysical data, the sedimentary characteristics of the Middle Permian Maokou Formation in the northern Sichuan Basin was studied by means of macroscopic and microscopic observation, geochemical element test, total organic carbon content and vitrinite reflectance measurement. There is a set of deep-water sediments rich in organic matter in the Guangyuan-Wangcang area of northern Sichuan during the late depositional period of the Middle Permian Maokou Formation. The strata are distributed from northwest to southeast, with thickness of 10–30 m, mainly composed of siliceous rocks and siliceous mudstones, intercalated with gravity flow deposits. Siliceous rocks and siliceous mudstones are characterized by thin single layer, flat bedding and rich siliceous radiolarians, calthrop and brachiopod with small body and thin shell, belonging to the typical sedimentary characteristics of deep-water trough facies. The contents of Cu, Co, Mo, Ni and the ratio of Ni to Co in the geochemical tests all indicate that the siliceous rocks are products of deep-water reducing environment. The TOC value ranges from 3.21% to 8.19%, with an average of 5.53%, indicating that the siliceous rocks have good hydrocarbon generation ability. The south side of the trough is in platform margin facies with high energy, and the sediments are mainly thick massive micritic-calcsparite biogenic (clastic) limestone, which is conducive to the formation and evolution of the reservoir. During the late sedimentary period of the Maokou Formation, the northward subduction and extension of the oceanic crust at the northwestern margin of the Yangtze Plate provided the internal dynamic conditions for the formation of the “Guangyuan-Wangcang” trough. According to the location, sedimentary characteristics and formation dynamics of the trough, it is similar to the “Kaijiang-Liangping” trough during Late Permian proposed by previous researchers. It is believed that the “Kaijiang-Liangping” trough already had its embryonic form during the Late Middle Permian.

Experimental Simulation of Hydrocarbon Expulsion in Semi-open Systems from Variable Organic Richness Source Rocks

To better understand oil and gas generation and expulsion mechanisms and their controlling factors, two-stage heating program (20 and 5 °C/d) at 11 target temperatures (250–580 °C) have been performed in a semi-open reactor on nine immature lacustrine shale samples from the Triassic Yanchang Formation in Ordos Basin, NW China, with total organic carbon (TOC) contents ranging from 0.5% to 30.0%. The cumulative expelled oil and gas were quantified and correlated with the measured vitrinite reflectance (%Ro) and residual TOC. The amount of expelled oil increases substantially with increasing maturity in the Ro range of 0.5–1.25% and ends at Ro of >1.45%, while the volume of expelled gas increases markedly with maturity when Ro is >1.0%. Organic richness exerts primary control on the expulsion yields, which increase linearly with increasing original TOC (TOCo) per unit weight of rock, whereas the increment decreases with TOCo per unit weight of TOC, once the TOCo content is above 5%. Marked TOC reduction occurs in the Ro of 0.5–1.1% due to oil generation and expulsion, but the trend is reversed in the higher maturity range possibly caused by the simultaneous decomposition of minerals. Numerical correlations among heating temperatures, %Ro, TOC content, and expelled oil and gas yields have been constructed, and the minimum TOC contents for effective oil and gas source rocks have been inferred. The lowest TOC contents of 0.5% and 0.48% are required for oil and gas expulsion in the oil and gas generation window, corresponding to the TOCo of 0.91% and 0.76%, respectively. The minimum TOC content for effective gas source rocks decreases slightly with increasing maturity; however, a much higher TOC cutoff is required for lower maturity level source rocks. Wide range of TOC content variation in our studied samples provides well constraint of organic richness on oil and gas generation and expulsion behaviors and their evolution trajectory during thermal evolution, which will fascinate source rock quality and exploration potential assessment in other source rock systems.

Source rock potential assessment of the Paleocene coal and coaly shale in the Attock-Cherat Range of Pakistan

In this study the hydrocarbon generation potential of the coal and coaly shale samples collected from coal mines in Attock-Cherat Range of Pakistan is optically and analytically evaluated. These samples, representing the Paleocene Hangu Formation, are analyzed across a range of thermal maturity stages to understand their hydrocarbon generation potential. The visual examination of maceral type and values of vitrinite reflectance have been considered while interpreting the geochemical results for the coal and associated sediments from the Paleocene Hangu Formation. The maceral group is dominated by vitrinite, mainly collodetrinite, followed by inertinite and liptinite, and suggests Type III kerogen for the samples. The geochemical parameters suggest that the samples are post mature, however, the vitrinite reflectance measurements show late mature conditions for a gas-prone generation. The overall petrographical and geochemical data suggest that the coal and coaly shale appear to occupy the gas window and fall in the dry gas zone. Based on the maceral types and Rock–Eval data, an anoxic to terrestrial environment is inferred for the deposition of the coal and associated sediments. The vitrinite reflectance, Rock–Eval pyrolysis, and the type and frequency of macerals show that the coal is of good quality, i.e., medium to high volatile bituminous and hard brown coal, mature, and is lying in the gas window. Oxygen index is continuously low throughout the analyzed interval, which further supports that the coal is of good quality.

Assessing extreme maturities – Challenging examples from immature Jordanian to overmature Far Eastern unconventional formations

Thermal maturity is often readily available from optical vitrinite reflectance measurements, but in marine sediments with absence of terrigenous organic material (vitrinite macerals) or formations older than the Devonian, this technique has limitations. Raman spectroscopy has been applied as an alternative measurement to infer thermal maturity in challenging formations. Organic-rich outcrop samples from the Jordanian Lajjoun and Sultani deposits and from a Far East shale were characterized for their key geochemical properties (bulk chemical and mineral composition, total organic carbon content) and thermal maturity. Bulk mineral and chemical abundances were quantified using standard X-ray diffraction and X-ray fluorescence techniques. Total organic carbon (TOC) content was calculated from programmed temperature pyrolysis. Thermal maturity was determined and compared using conventional vitrinite reflectance and a novel, rapid laser Raman spectroscopy method. The Jordanian samples are organic-rich (16.3–17.4 wt% TOC), while the Far Eastern sample is relatively organic-lean (2 wt% TOC). Programmed pyrolysis shows that the Jordanian samples seem immature with high remaining hydrocarbon generative potential (S2), whereas the sample from the Far East appears to be overmature with extremely low S2 value. These findings were confirmed by the results from organic petrography as well as through Raman spectroscopic measurements. The Far Eastern samples are suggested to be highly mature (4.6–5.7% VRE), whereas the Jordanian samples were found to be immature (0.4–0.5% VRE). Robust Raman maturity determination allows to define and refine petrophysical properties of kerogen and thus enhance the accuracy in predicting hydrocarbon in place and the potential for its recovery.

Paleotemperature modeling of hydrocarbon generation centers and their role in the formation of «Paleozoic» oil deposits (Ostaninskoe field, Tomsk region)

Study and exploration of the pre-Jurassic oil and gas complex in Western Siberia is one of the aspects of hydrocarbon raw-material base development. The main scope of this study is to locate the source of Paleozoic hydrocarbons. The problem of modeling and assessing the role of Paleozoic-Mesozoic hydrocarbon generation centers in the formation of «Paleozoic» oil deposits in the section of the Ostaninskoe oil and gas condensate field (Tomsk region) is solved. In the formation of the oil and gas content of the pre-Jurassic basement two reservoirs are involved: the weathering crust and the roof of the bed-rock Paleozoic. The first was formed during the period of 213–208 Ma, and the second is genetically determined by epigenetic processes in the weathering crust. Potential hydrocarbon sources for the weathering crust and bed-rock Paleozoic reservoirs are Domanic type rocks in the crystalline basement: Larinskaya S1lr, Mirnaya D1mr, Chuzikskaya D2cz, Chaginskaya D3cg Formations, as well as Tyumenskaya J1-2tm and Bazhenovskaya J3bg Formations in sedimentary cover. To perform joint paleotemperature modeling of sedimentary basins of the «modern» Jurassic-Cretaceous and Paleozoic «paleobasins», the Ostaninskaya 438P well was selected, which is due to the presence of measured temperatures both in the Jurassic sections and in the pre-Jurassic formations, as well as fluid inflows from the pre-Jurassic horizons into the well. At the first step, the solution of the inverse problem of geothermics was obtained using reservoir temperatures and vitrinite reflectance measurements from the Mesozoic deposits: density of deep heat flow from the base of sedimentary section was determined, which is characterized by a quasi-constant value from the Jurassic to the present. The second step was to solve the inverse problem using vitrinite reflectance measurements from Paleozoic sediments. As a result, the heat flow value was obtained for the key moments of geodynamic history of the stratigraphic section, starting from the Silurian. By solving direct problems of geothermics with the given values of heat flow, the structural-tectonic and thermal history of four Paleozoic potential oil source formations (as well as Jurassic – Bazhenov and Tyumen Formations) has been retraced. The controversial aspects of the heat transfer model in the section of the Ostaninskoe field are considered. It has been established that the Tyumen and Bazhenov oil sources (most likely Bazhenov) are syngenetic (in terms of generation, accumulation and preservation time) for the weathering crust and the Paleozoic reservoirs. The role of the Chaginskaya Formation as gas source is insignificant.

Szenes anyagok maximális átalakulási hőmérsékletének meghatározása Raman-spektroszkópiai mérésekkel: standardizálás és esettanulmány az Aggtelek–Rudabányai-hegységből

A mély diagenetikus – kisfokú metamorf üledékes kőzetek csúcshőmérsékletének meghatározását illit (Küblerindex) és klorit „kristályossági”, valamint vitrinit reflexiós értékek alapján nagy bizonytalanság terheli. A hőmérséklet pontosabb meghatározására az elmúlt időszakban egyre elterjedtebbé vált a szenes anyag szemcsék mérésén alapuló Raman-spektroszkópia. Jelen munka célja, hogy a szenes anyag Raman-spektroszkópia (RSCM) egyik módszerének alapjairól, valamint hazai alkalmazási lehetőségeiről adjon részletes, magyar nyelvű összefoglalást. A bemutatott módszer alkalmazásához elengedhetetlen egy ismert metamorf csúcshőmérsékletű referencia kőzetsorozat elemzése, amely az ismeretlen minták metamorf csúcshőmérsékletének meghatározásához szükséges kalibrációs görbe alapjául szolgál. Ez a referencia kőzetsorozat teszi lehetővé az egyes laboratóriumokban született eredmények összehasonlíthatóságát is. Munkánkban ismertetjük az ELTE TTK KKIC Raman-laboratóriumában mért referencia kőzetsorozat eredményeit, valamint az ez alapján létrehozott kalibrációs görbét. A módszer alkalmazhatóságát az Aggtelek–Rudabányai-hegység Telekesoldali Formációjának példáján mutatjuk be. Az öt mintán (négy fúrás, egy felszíni) elvégzett mérések alapján az összletre meghatározott metamorf csúcshőmérséklet 273 ± 10 °C-nak adódott, amely adat jelentősen pontosabb a korábban rendelkezésre álló illit- és klorit kristályossági, valamint vitrinit reflexiós értékek alapján becsült metamorf csúcshőmérsékleti értékeknél. A módszer kitűnően kiegészíti, valamint részben helyettesítheti a szénhidrogén-, illetve szén geológiában alkalmazott vitrinit reflexió méréseket.

Consideration of the limitations of thermal maturity with respect to vitrinite reflectance, Tmax, and other proxies

Many of those assessing geochemical data have taken a “cookbook” approach to interpretation. Such an approach generally does not take into consideration the limitations of the different data sets. Among these data sets are those associated with thermal maturity, which guides the interpretation of the extent of generation and hydrocarbon phase. The temperature of peak pyrolysis generation (Tmax) is commonly used to map thermal maturity directly or through a conversion to vitrinite reflectance equivalent values. Such efforts do not take into consideration analytical uncertainties or natural variability within a stratigraphic unit at any given locality. Furthermore, when presented as vitrinite reflectance equivalents, the associated error in the conversion is not considered, yet the values are presented as “absolutes.” When examining vitrinite reflectance, there are also several issues that should be considered. Individual mean values are commonly considered out of context. All thermal maturity indicators, including vitrinite reflectance, need to be placed into a geologic framework, and trends rather than discrete values should be considered. The nature of the studied samples is also significant. Whole-rock and isolated kerogen analyses yield different results, commonly because of the lack of a statistically meaningful number of individual measurements because of either low organic carbon or low concentrations of vitrinite when examining whole-rock samples. Such differences are not trivial, with final interpretation of hydrocarbon phase boundaries potentially being shifted. Bitumen reflectance shares some of the same issues as vitrinite reflectance measurement, including misidentification, the presence of multiple populations and insufficient measurements, and the possibility that environmental factors may influence the observed reflectance. Conversion issues of bitumen to vitrinite reflectance are similar to those identified for the Tmax conversion.

Comprehensive thermal maturity assessment in shales: a case study on the upper cretaceous Qingshankou formation (Songliao Basin, NE China)

The Songliao Basin is the largest Early Cretaceous lacustrine rift basin of northeast China and hosts tremendous conventional and unconventional petroleum resources. However, the distribution of shale oil is not well constrained, as production from source rock reservoirs requires certain thermal maturity cut-offs (vitrinite reflectance of > 0.8%Rr). In this study, the thermal maturity of the Qiangshankou Formation along the Southern Uplift and in the Central Depression of the Songliao Basin was evaluated by combining traditional and advanced petrographic and geochemical maturity proxies with clay mineralogical investigations. The Qingshankou Formation is one of the major source rocks of the region, but previous studies encountered difficulties in obtaining reliable maturity data, mainly due to strongly shifted Tmax values. Equally, Tmax determined during this study showed apparent shifting likely caused either by retained solid bitumen or by variations in kerogen type. In contrast, the measured vitrinite reflectance shows a reliable depth trend, meeting the shale oil cut-off maturity of 0.8%Ro at a drilling depth of ~ 2300 m, which is only reached in the Central Depression of the basin. The vitrinite reflectance trend is supported by changes in clay mineralogy, such as the progressing ordering of I/S mixed layers (“Reichweite”), increasing illitization, decreasing detrital kaolinite and correspondingly increasing authigenic chlorite contents. Maturity-related biomarker proxies are only partly valid; while the methylphenanthrene index (MPI-1) and the trimethylnaphthalene ratio (TNR-1) show reliable maturity trends even over short depth intervals, other established proxies (e.g. based on alkylbiphenyls) proved insensitive to changes from immature to peak oil mature and are, therefore, not recommended for further use in studies on Qingshankou Fm. shales. In summary, the combination of various maturity parameters improves the understanding of shale oil distribution in the central Songliao Basin, providing valuable insights for studies on similar unconventional targets in the region.

Berea Sandstone: New developments in a mature oil and gas play, eastern Kentucky and Ohio

With development dating from the 1800s, the Devonian Berea Sandstone has a long history of oil and gas development in the Appalachian Basin. A new phase of development began in northeastern Kentucky in 2011 with production of high-gravity oil from horizontal wells at depths less than 2200 ft (<671 m). Oil production in areas previously unproductive or primarily gas productive was unexpected because thermal-maturity measures, such as vitrinite reflectance, suggested source rocks should be immature. Moreover, downdip the Berea Sandstone appeared to produce primarily gas within the oil window. Organic petrography and geochemical analyses were conducted on source rocks overlying (Sunbury Shale) and underlying (Ohio Shale) the Berea Sandstone and produced oil and gas from the Berea Sandstone and Ohio Shale. Samples were collected from southernmost Ohio to southeastern Kentucky along a northwest-to-southeast transect representing increased burial depth. Geochemistry results suggest the Sunbury or Ohio Shales could be sources of oil reservoired in the Berea Sandstone. Migration is necessary to account for oil in the updip parts of the play. Vitrinite reflectance measurements suggest, however, the area mature for oil is larger compared to previous assessments. Consequently, less migration is needed to account for the distribution of oil production. Gas chemistry reflects the thermal-maturity effect of regional dip with additional influence from local structures. Stratigraphic analysis of the Berea Sandstone in core and outcrop shows it to be primarily a siltstone with lateral facies changes, different bedding types, and diagenesis producing a complex reservoir.

Composition of organic matter and thermal maturity of Mesozoic and Cenozoic sedimentary rocks in East Herzegovina (External Dinarides, Bosnia and Herzegovina)

This paper presents the first data on the organic matter and thermal maturity of Mesozoic and Cenozoic sedimentary rocks in the East Herzegovina region of the External Dinarides. Representative, organic-rich samples from outcropping sedimentary rocks of different ages in the area (Triassic to Neogene) were selected and analysed. The organic matter was studied by Rock-Eval pyrolysis and under the microscope in reflected non-polarized light and incident blue light. The results obtained show the presence of different types of organic matter in the area and thermal maturity stages from immature (Cenozoic) to early mature (Mesozoic). Vitrinite is abundant in the samples analysed, with the exception of Cretaceous samples that contain mostly lamalginite and bituminite. While measured vitrinite reflectance in end-member samples (Triassic shale 0.78 % Rr and Neogene coal 0.34% Rr) are in good correlation with the Tmax parameter from Rock-Eval pyrolysis. T max generally shows lower values in most Mesozoic samples. The organic petrographic data indicate that specific kerogen in Cretaceous and some Triassic sedimentary rocks is a probable reason for the significantly lower T max values. In addition, the results of pyrolysis documented before and after extraction revealed that free hydrocarbons (bitumen) in the surface samples analysed suppress the Tmax values.

Modelovanje geotermičke evolucije sedimentnih stena istočne Hercegovine na osnovu refleksije vitrinita

This paper presents the first results of the geothermal evolution modeling in East Herzegovina based on vitrinite reflectance calculations and measurements. Modeling of burial and geothermal was performed using "SimpleMat" software with well known kinetic model of vitrinite reflectance - EASY % Ro. By fitting the calculated reflectance values with mean measured vitrinite reflectances, it was concluded that there was erosion of some 900 m in the area, and that first possible petroleum generation could have started some 100 Ma ago. According to final calibration model that includes additional thickness and subsequent erosion of Paleogene sequence, the Upper Triassic sediments should have maturity from 0.70 to 1.1 % Rr, Lower Jurassic from 0.62 to 0.70 % Rr, whereas Upper Cretaceous sediments should have values from 0.40 to 0.60 % Rr, which is in accordance with measured vitrinite reflectance in 23 samples. Assuming that beginning of oil window in the East Herzegovina correspond to the vitrinite reflectance of 0.50 % Rr, all analyzed Mesozoic samples are at the initial stage of catagenesis ("oil window"), while Cenozoic sediments are at the stage of diagenesis.

Hydrocarbon generation-retention-expulsion mechanism and shale oil producibility of the permian lucaogou shale in the Junggar Basin as simulated by semi-open pyrolysis experiments

The shale of the Permian Lucaogou Formation in the Jimusar sag, Junggar Basin (abbreviated as the Lucaogou shale) is a typical lacustrine type-II source rock, and is among the most representative target zones for shale oil exploration in China. However, little attention has been paid to the dynamic changes of the shale decomposition; hydrocarbon generation, retention, and expulsion; physico-chemical properties; and producibility of shale oil at different stages of maturation in this shale. Semi-open pyrolysis experiments were performed on the Lucaogou shale; products including expelled gas, oil (expelled oil), bitumen (retained oil), and residual rock were obtained, and their quantities and chemical and physical compositions were comprehensively characterized. The results show that the density and molecular weight of the oil are lower than those of the bitumen, whereas the API gravity of the oil is higher than that of the bitumen, indicating the preferential expulsion of light hydrocarbons and short chains. The saturate, aromatic, resin and asphaltene (SARA) percentages of oils under the current semi-open pyrolysis experiments were similar to those of natural oils recovered from the Lucaogou Formation, suggesting that semi-open pyrolysis can achieve the same purpose as hydrous pyrolysis to simulate natural oil composition. The measured vitrinite reflectance (Ro) of the pyrolyzed shale was lower than the calculated Easy%Ro, which is in accord with findings from the Chang 7 shale (another typical lacustrine type-II shale in China) but distinct from previously reported type-III coals and marine type-II shales. Similar to the Chang 7 shale, the decomposition process of the Lucaogou shale did not follow the sequential reaction model described as kerogen → bitumen → oil or kerogen → NSOs → HCs. The generation of HCs (oil) and NSOs (bitumen) was independent and followed the “alternate pathway” mechanism under semi-open pyrolysis conditions. In the early oil window (Ro ˂ 1.0%), the hydrocarbon expulsion efficiency was relatively low, meaning that the shale simultaneously retained considerable amounts of oil during peak oil generation. The producibility of shale oil reached its maximum at the end of the oil window (1.0–1.2 %Ro), and this interval is considered the most suitable for fracturing technology.