Liquid hydrocarbon characterization of the lacustrine Yanchang Formation, Ordos Basin, China: Organic-matter source variation and thermal maturity

Source-rock samples from the Upper Triassic Yanchang Formation in the Ordos Basin of China were geochemically characterized to determine variations in depositional environments, organic-matter (OM) source, and thermal maturity. Total organic carbon (TOC) content varies from 4 wt% to 10 wt% in the Chang 7, Chang 8, and Chang 9 members — the three OM-rich shale intervals. The Chang 7 has the highest TOC and hydrogen index values, and it is considered the best source rock in the formation. Geochemical evidence indicates that the main sources of OM in the Yanchang Formation are freshwater lacustrine phytoplanktons, aquatic macrophytes, aquatic organisms, and land plants deposited under a weakly reducing to suboxic depositional environment. The elevated [Formula: see text] sterane concentration and depleted [Formula: see text] values of OM in the middle of the Chang 7 may indicate the presence of freshwater cyanobacteria blooms that corresponds to a period of maximum lake expansion. The OM deposited in deeper parts of the lake is dominated by oil-prone type I or type II kerogen or a mixture of both. The OM deposited in shallower settings is characterized by increased terrestrial input with a mixture of types II and III kerogen. These source rocks are in the oil window, with maturity increasing with burial depth. The measured solid-bitumen reflectance and calculated vitrinite reflectance from the temperature at maximum release of hydrocarbons occurs during Rock-Eval pyrolysis ([Formula: see text]) and the methylphenanthrene index (MPI-1) chemical maturity parameters range from 0.8 to [Formula: see text]. Because the thermal labilities of OM are associated with the kerogen type, the required thermal stress for oil generation from types I and II mixed kerogen has a higher and narrower range of temperature for hydrocarbon generation than that of OM dominated by type II kerogen or types II and III mixed kerogen deposited in the prodelta and delta front.

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Characteristics of Organic Macerals and Their Influence on Hydrocarbon Generation and Storage: A Case Study of Continental Shale of the Yanchang Formation from the Ordos Basin, China

Geofluids ◽

10.1155/2021/5537154 ◽

2021 ◽

Vol 2021 ◽

pp. 1-17

Author(s):

Lei Xiao ◽

Zhuo Li ◽

Yufei Hou ◽

Liang Xu ◽

Liwei Wang ◽

...

Keyword(s):

Organic Matter ◽

Source Rock ◽

Thermal Evolution ◽

Ordos Basin ◽

Type I ◽

Hydrocarbon Generation ◽

Yanchang Formation ◽

Weight Percentage ◽

Generation Capacity ◽

And Storage

Organic macerals are the basic components of organic matter and play an important role in determining the hydrocarbon generation capacity of source rock. In this paper, organic geochemical analysis of shale in the Chang 7 member of the Yanchang Formation was carried out to evaluate the availability of source rock. The different organic macerals were effectively identified, and the differences in hydrocarbon generation and pore-forming capacities were discussed from two perspectives: microscopic pore development and macroscopic hydrocarbon generation through field emission scanning electron microscopy (FE-SEM) and energy-dispersive spectrum (EDS) analyses, methane isotherm adsorption, and on-site analysis of gas-bearing properties. The results show that the source rock of the Chang 7 member has a high abundance of organic matter and moderate thermal evolution and that the organic matter type is mainly type I. Based on the morphology of the organic matter and the element and pore development, four types of hydrogen-rich macerals, including sapropelite and exinite, and hydrogen-poor macerals, including vitrinite and inertinite, as well as the submacerals, algae, mineral asphalt matrix, sporophyte, resin, semifusinite, inertodetrinite, provitrinite, euvitrinite, and vitrodetrinite, can be identified through FE-SEM and EDS. A large number of honeycomb-shaped pores develop in sapropelite, and round-elliptical stomata develop in exinite, while vitrinite and inertinite do not develop organic matter pores. The hydrogen-rich maceral is the main component of organic macerals in the Chang 7 member of the Yanchang Formation. The weight percentage of carbon is low, so it has good hydrocarbon generation capacity, and the organic matter pores are developed and contribute 97% of the organic matter porosity, which is conducive to hydrocarbon generation and storage. The amount of hydrogen-poor maceral is low, and the weight percentage of carbon is low, and the organic matter pores are not developed, which is not conducive to hydrocarbon generation and storage.

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Facies, rock attributes, stratigraphy, and depositional environments: Yanchang Formation, Central Ordos Basin, China

Interpretation ◽

10.1190/int-2016-0122.1 ◽

2017 ◽

Vol 5 (2) ◽

pp. SF15-SF29 ◽

Cited By ~ 9

Author(s):

Stephen C. Ruppel ◽

Harry Rowe ◽

Kitty Milliken ◽

Chao Gao ◽

Yongping Wan

Keyword(s):

Organic Matter ◽

Clay Mineral ◽

Ordos Basin ◽

Depositional Environments ◽

Source Rocks ◽

Late Triassic ◽

Great Promise ◽

Yanchang Formation ◽

X Ray ◽

Stacking Patterns

The Late Triassic Yanchang Formation (Fm) is a major target of drilling for hydrocarbons in the Ordos Basin. Although most of the early focus on this thick succession of lacustrine rocks has been the dominant deltaic sandstones and siltstones, which act as local reservoirs of oil and gas, more recent consideration has been given to the organic-rich mudstone source rocks. We used modern chemostratigraphic analysis to define vertical facies successions in two closely spaced cores through the Chang 7 Member, the primary source rock for the Yanchang hydrocarbon system. We used integrated high-resolution X-ray fluorescence and X-ray diffraction measurements to define four dominant facies. Variations in stable carbon isotopes mimic facies stacking patterns, suggesting that terrigenous organic matter (although minor in volume) is associated with the arkoses and sandstones, whereas aquatic organic matter is dominant in the mudstones. Facies stacking patterns define three major depositional cycles and parts of two others, each defined by basal mudstone facies that document basin flooding and deepening (i.e., flooding surfaces). Unconfined compressive strength measurements correlate with clay mineral abundance and organic matter. Comparisons of core attributes with wireline logs indicate that although general variations in clay mineral volumes (i.e., mudstone abundance) can be discerned from gamma-ray logs, organic-matter distribution is best defined with density or resistivity logs. These findings, especially those established between the core and log data, provide a powerful linkage between larger scale facies patterns and smaller scale studies of key reservoir attributes, such as pore systems, mineralogy, diagenesis, rock mechanics, hydrocarbon saturation, porosity and permeability, and flow parameters. This first application of modern chemostratigraphic techniques to the Yanchang Fm reveals the great promise of applying these methods to better understand the complex facies patterns that define this lacustrine basin and the variations in key reservoir properties that each facies displays.

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Source Rock Characterization of Silurian Tanezzuft and Devonian Awaynat Wanin Formations the Northern Edge of the Murzuq Basin, South West Libya

Petroleum & Petrochemical Engineering Journal ◽

10.23880/ppej-16000216 ◽

2020 ◽

Vol 4 (1) ◽

pp. 1-13

Author(s):

Aboglila S

Keyword(s):

Organic Matter ◽

Source Rock ◽

Depositional Environments ◽

Source Rocks ◽

Thermal Maturity ◽

Maturity Level ◽

Geochemical Parameters ◽

Northern Edge ◽

Rock Characterization ◽

Tanezzuft Formation

Drill cutting samples (n = 92) from the Devonian Awaynat Wanin Formation and Silurian Tanezzuft Formation, sampled from three wells F1, G1 and H1, locate in the northern edge of the Murzuq basin (approximately 700 kilometers south of Tripoli). The studied samples were analyzed in the objective of their organic geochemical assessment such as the type of organic matter, depositional conditions and thermal maturity level. A bulk geochemical parameters and precise biomarkers were estimated, using chromatography-mass spectrometry (GC-MS) to reveal a diversity of their geochemical characterizations. The rock formations are having varied organic matter contents, ranged from fair to excellent. The total organic carbon (TOC) reached about 9.1 wt%, ranging from 0.6 to 2.93 wt% (Awaynat Wanin), 0.5 to 2.54 wt% (Tanezzuft) and 0.52 to 9.1 wt% (Hot Shale). The cutting samples are ranged oil-prone organic matter (OM) of hydrogen index (HI) ranged between 98 –396 mg HC/g TOC, related kerogen types are type II and II/III, with oxygen index (OI): 6 - 190 with one sample have value of 366 mg CO2/g. Thermal maturity of these source rocks is different, ranging from immature to mature and oil window in the most of Tanezzuft Formation and Hot Shale samples, as reflected from the production index data (PI: 0.08 - 034). Tmax and vitrinite reflectance Ro% data (Tmax: 435 – 454 & Ro%: 0.46 - 1.38) for the Awaynat Wanin. Biomarker ratios of specific hydrocarbons extracted from represented samples (n = 9), were moreover used to study thermal maturity level and depositional environments. Pristine/Phytane (Pr/Ph) ratios of 1.65 - 2.23 indicated anoxic to suboxic conditions of depositional marine shale and lacustrine source rock.

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Petroleum Geochemistry of the Loperot-1 Well in Lokichar Basin, Kenya

10.2118/afrc-2557372-ms ◽

2016 ◽

Cited By ~ 1

Author(s):

David M. Katithi ◽

David O. Opar

Keyword(s):

Organic Matter ◽

Source Rock ◽

Shale Gas ◽

Source Rocks ◽

Geochemical Data ◽

Mature Stage ◽

Type I ◽

Hydrocarbon Generation ◽

Gas Generation ◽

Gas Targets

ABSTRACT The work reports an in-depth review of bulk and molecular geochemical data to determine the organic richness, kerogen type and thermal maturity of the Lokhone and the stratigraphically deeper Loperot shales of the Lokichar basin encountered in the Loperot-1 well. Oil-source rock correlation was also done to determine the source rocks’ likelihood as the source of oil samples obtained from the well. A combination of literature and geochemical data analyses show that both shales have good to excellent potential in terms of organic and hydrogen richness to act as conventional petroleum source rocks. The Lokhone shales have TOC values of 1.2% to 17.0% (average 5.16%) and are predominantly type I/II organic matter with HI values in the range of 116.3 – 897.2 mg/g TOC. The Lokhone source rocks were deposited in a lacustrine depositional environment in episodically oxic-dysoxic bottom waters with periodic anoxic conditions and have Tmax values in addition to biomarker signatures typical of organic matter in the mid-mature to mature stage with respect to hydrocarbon generation and immature for gas generation with Ro values of 0.51 – 0.64%. The Loperot shales were shown to be possibly highly mature type II/III source rocks with TOC values of 0.98% – 3.18% (average 2.4%), HI of 87 – 115 mg/g TOC and Ro of 1.16 – 1.33%. The Lokhone shale correlate well with the Loperot-1 well oils and hence is proposed as the principal source rock for the oils in the Lokichar basin. Although both source rocks have good organic richness to act as shale gas plays, they are insufficiently mature to act as shale gas targets but this does not preclude their potential deeper in the basin where sufficient gas window maturities might have been attained. The Lokhone shales provide a prospective shale oil play if the reservoir suitability to hydraulic fracturing can be defined. A basin wide study of the source rocks thickness, potential, maturation and expulsion histories in the Lokichar basin is recommended to better understand the present-day distribution of petroleum in the basin.

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Climate-Provenance Effect on the Organic Matter Enrichment of the Chang 9 Source Rocks in the Central Ordos Basin, China

Geofluids ◽

10.1155/2021/1233879 ◽

2021 ◽

Vol 2021 ◽

pp. 1-10

Author(s):

Ling Ma ◽

Zhihuan Zhang ◽

Weiqiu Meng

Keyword(s):

Organic Matter ◽

Chemical Weathering ◽

Ordos Basin ◽

Source Rocks ◽

Sediment Provenance ◽

Type I ◽

Hydrocarbon Generation ◽

Hydrocarbon Generation Potential ◽

Primary Producer ◽

Geochemical Analyses

The Upper Triassic Chang 9 organic-rich sediments have been considered as effective hydrocarbon source rocks for the Mesozoic petroleum system in the Ordos Basin. Previous studies on the Chang 9 member mostly focused on the influence of their paleoproductivity and paleoredox conditions on the organic matter (OM) enrichment, whereas there are few studies on the influence of the paleoclimate condition and sediment provenance on the OM enrichment. In this study, a series of geochemical analyses was performed on the Chang 9 core samples, and their hydrocarbon generation potential, paleoclimate condition, and sediment provenance were assessed to analyze the effect of paleoclimate-provenance on OM enrichment. The Chang 9 source rocks are characterized by high OM abundance, type I−II OM type, and suitable thermal maturity, implying good hydrocarbon generation potential. Based on the C-values and Sr/Cu ratios, the paleoclimate condition of the Chang 9 member was mainly semihumid. In addition, the Th/Co vs. La/Sc diagram and negative δEuN indicate that the Chang 9 sediments were mainly derived from felsic source rocks. Meanwhile, the paleoweathering intensity of the Chang 9 member is moderate based on moderate values of CIA, PIA, and CIW, which corresponds to the semihumid paleoclimate. The relatively humid paleoclimate not only enhances photosynthesis of the primary producer, but also promotes chemical weathering intensity, leading to suitable terrestrial clastic influx to the lacustrine basin, which is beneficial for OM enrichment.

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Using aromatic biological markers as a tool for assessing thermal maturity of source rocks in the Campano-Maastrichtian Mamu Formation, southeastern Nigeria

Earth Sciences Research Journal ◽

10.15446/esrj.v18n1.34799 ◽

2014 ◽

Vol 18 (1) ◽

pp. 51-62 ◽

Cited By ~ 4

Author(s):

Jude E. Ogala ◽

Mike I. Akaegbobi

Keyword(s):

Organic Matter ◽

Aromatic Hydrocarbons ◽

Mixed Type ◽

Higher Plants ◽

Vitrinite Reflectance ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Type Ii ◽

Thermal Maturity ◽

Southeastern Nigeria

The concentration and distribution of aromatic biomarkers in coals and shales from five boreholes penetrating the Maastrichtian Mamu Formation of the Anambra Basin, southeastern Nigeria, were investigated by gas chromatography-mass spectrometryto assess the thermal maturity and organic matter input. The study focused on the variations of the relative abundances of naphthalenes, phenanthrenes, and monaromatic and triaromatic steroids identified on the mass fragmentograms. Trimethylnaphthalene(TMN) is the most abundant member of the naphthalene family while methylphenanthrene (MP) is the most abundant phenanthrene family member. The total of phenanthrenes and their isomers was greater than that of naphthalenes. The distribution of these aromatic hydrocarbons and their akyl derivatives was strongly controlled by a selective expulsion mechanism and thermal maturation of organic matter. The low dibenzothiophene/phenanthrene (DBT/PHEN) ratios (0.01-0.06), as well as the enhanced concentrations of 1,2,5-TMN relative to 1,2,7- TMN,indicates organic matter derived mainly from higher plants,and the extract ternary plot of C27, C28 and C29 monoaromatic steroids suggests a Type III and mixed Type II/III kerogen. The calculated mean vitrinite reflectance (%Rm), determined from the distributions of the isomers of methyldibenzothiophene ratio (MDR) in the rock extracts, ranged from 0.51 to 1.43. These maturity values indicate that the coal and shale extracts are marginally mature for hydrocarbon generation. ResumenLa concentración y distribución de biomarcadores aromáticos en carbones y esquistos de cinco perforaciones en la formación Maastrichtian Mamu de la cuenca de Anambra, en el sureste de Nigeria, fueron analizados a través de un estudio de espectometría cromatográfico y de masa del gas para medir la madurez termal y la entrada de material orgánico. El estudio está enfocado en las variaciones de la abundancia relativa de naftalinas y fenantrenos, y en los esteroides monoaromáticos y triaromáticos identificados en los fragmentogramas de masas. La trimetinaftalina (TMN) es la más abundante de la familia de las naftalinas mientras el metilfenantreno (MP) es el más abundante de los fenantrenos. El tota de los fenantrenos y sus isómeros fue mayor que el de las naftalinas. La distribución de estos hidrocarbones aromáticos y sus alquilos derivados fue controlada ampliamente por un mecanismo de expulsión selectiva y de la maduración térmica de material orgánico. La baja proporción dibenziotofeno/fenantreno (DBT/ PHEN) (0.01-0.06), al igual que las concentraciones mejoradas de 1,2,5-TMN relativas de 1,2,7-TMN indican que la materia orgánica se deriva principalmente de plantas mayores, y del diagrama terniario de los esteroides monoaromáticos C27, C28 y C29 sugiere un tipo III mezclado con tipos II/III de querógenos. El valor calculado de la reflectancia de vitrinita (%Rm) determinado de la proporción de isómeros de metildibenziotofeno (MDR) en los extractos rocosos oscila de 0.51 a 1.43. Estos valores de madurez indican que los extractos de carbones y esquistos son marginalmente maduros para la generación de hidrocarbono.

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Study on Geochemical Characteristics of tight sandstone gas accumulation in Linxing area

E3S Web of Conferences ◽

10.1051/e3sconf/202020601017 ◽

2020 ◽

Vol 206 ◽

pp. 01017

Author(s):

Yangbing Li ◽

Weiqiang Hu ◽

Xin Chen ◽

Litao Ma ◽

Cheng Liu ◽

...

Keyword(s):

Source Rock ◽

Ordos Basin ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Light Hydrocarbons ◽

Tight Sandstone ◽

Source Type ◽

Reservoir Type ◽

Sandstone Reservoir ◽

Main Component

Based on the comprehensive analysis of the characteristics of tight sandstone gas composition, carbon isotope, light hydrocarbons and source rocks in Linxing area of Ordos Basin, the reservoir-forming model of tight sandstone gas in this area is discussed. The study shows that methane is the main component of tight sandstone gas, with low contents of heavy hydrocarbons and non-hydrocarbons, mainly belonging to dry gas in the Upper Paleozoic in Linxing area. The values of δ13C1, δ13C2 and δ13C3 of natural gas are in the ranges of -45.6‰ ~ -32.9‰, -28.9‰ ~ -22.3‰ and -26.2‰~ -19.1‰, respectively. The carbon isotopic values of alkane gas show a general trend of positive carbon sequence. δ13C1 value is less than -30‰, with typical characteristics of organic genesis. There is a certain similarity in the composition characteristics of light hydrocarbons. The C7 series show the advantage of methylhexane, while the C5-7 series mainly shows the advantage of isoalkane. The tight sandstone gas in this area is mainly composed of mature coal-derived gas, containing a small amount of coal-derived gas and oil-type gas mixture. According to the mode of hydrocarbon generation, diffusion and migration of source rocks in Linxing area, the tight sandstone gas in the study area can be divided into three types of reservoir-forming assemblages: the upper reservoir type of the far-source type (upper Shihezi formation-shiqianfeng formation sandstone reservoir-forming away from source rocks), the upper reservoir type of the near-source type ( the Lower Shihezi formation sandstone reservoir-outside the source rock), and the self-storage type of the source type (Shanxi formation-Taiyuan formation source rock internal sand reservoir).

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Geochemical characterization of hydrocarbon source rocks of the Triassic-Jurassic time interval in the Mandawa basin, southern Tanzania: Implications for petroleum generation potential

South African Journal of Geology ◽

10.25131/sajg.123.0037 ◽

2020 ◽

Vol 123 (4) ◽

pp. 587-596

Author(s):

A. Emanuel ◽

C.H. Kasanzu ◽

M. Kagya

Keyword(s):

Source Rocks ◽

Geochemical Data ◽

Time Interval ◽

Type I ◽

Hydrocarbon Generation ◽

Type Ii ◽

Geochemical Characterization ◽

Type Iii ◽

Petroleum Generation

Abstract Triassic to mid-Jurassic core samples of the Mandawa basin, southern Tanzania (western coast of the Indian Ocean), were geochemically analyzed in order to constrain source rock potentials and petroleum generation prospects of different stratigraphic formations within the coastal basin complex. The samples were collected from the Mihambia, Mbuo and Nondwa Formations in the basin. Geochemical characterization of source rocks intersected in exploration wells drilled between 503 to 4042 m below surface yielded highly variable organic matter contents (TOC) rated between fair and very good potential source rocks (0.5 to 8.7 wt%; mean ca. 2.3 wt%). Based on bulk geochemical data obtained in this study, the Mandawa source rocks are mainly Type I, Type II, Type III, mixed Types II/III and Type IV kerogens, with a predominance of Type II, Type III and mixed Type II/III. Based on pyrolysis data (Tmax 417 to 473oC; PI = 0.02 to 0.47; highly variable HI = 13 to 1 000 mg/gTOC; OI = 16 to 225 mg/g; and VR values of between 0.24 to 0.95% Ro) we suggest that the Triassic Mbuo Formation and possibly the mid-Jurassic Mihambia Formation have a higher potential for hydrocarbon generation than the Nondwa Formation as they are relatively thermally mature.

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Organic geochemical and palynological studies of the Maastrichtian source rock intervals in Bida Basin, Nigeria: implications for hydrocarbon prospectivity

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-020-00989-z ◽

2020 ◽

Vol 10 (8) ◽

pp. 3191-3206

Author(s):

Olusola J. Ojo ◽

Ayoola Y. Jimoh ◽

Juliet C. Umelo ◽

Samuel O. Akande

Keyword(s):

Organic Matter ◽

Source Rock ◽

Vitrinite Reflectance ◽

Source Rocks ◽

High Yield ◽

Thermal Maturity ◽

Hydrocarbon Source Rock ◽

Moderate Amount ◽

Oxic Condition ◽

Freshwater Swamp

Abstract The Patti Formation which consists of sandstone and shale offers the best potential source beds in the Bida Basin. This inland basin is one of the basins currently being tested for hydrocarbon prospectivity in Nigeria. Fresh samples of shale from Agbaja borehole, Ahoko quarry and Geheku road cut were analysed using organic geochemical and palynological techniques to unravel their age, paleoecology, palynofacies and source bed hydrocarbon potential. Palynological data suggest Maastrichtian age for the sediments based on the abundance of microfloral assemblage; Retidiporites magdalenensis, Echitriporites trianguliformis and Buttinia andreevi. Dinocysts belonging to the Spiniferites, Deflandrea and Dinogymnium genera from some of the analysed intervals are indicative of freshwater swamp and normal sea conditions. Palynological evidence further suggests mangrove paleovegetation and humid climate. Relatively high total organic carbon TOC (0.77–8.95 wt%) was obtained for the shales which implies substantial concentration of organic matter in the source beds. Hydrocarbon source rock potential ranges from 0.19 to 0.70 mgHC/g.rock except for a certain source rock interval in the Agbaja borehole with high yield of 25.18 mgHC/g.rock. This interval also presents exceptionally high HI of 274 mgHC/g.TOC and moderate amount of amorphous organic matter. The data suggests that in spite of the favourable organic matter quantity, the thermal maturity is low as indicated by vitrinite reflectance and Tmax (0.46 to 0.48 Ro% and 413 to 475 °C, respectively). The hydrocarbon extracts show abundance of odd number alkanes C27–C33, low sterane/hopane ratio and Pr/Ph > 2. We conclude that the source rocks were terrestrially derived under oxic condition and dominated by type III kerogen. Type II organic matter with oil and gas potential is a possibility in Agbaja area of Bida Basin. Thermal maturity is low and little, or no hydrocarbon has been generated from the source rocks.

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