Average Total Organic Carbon Content Research Articles

Petroleum source-rock characterization and the depositional environment of Kimmeridgian–Tithonian sequences, Jaisalmer Basin, western Rajasthan, India

In hydrocarbon exploration, total organic carbon (TOC) content and Rock-Eval pyrolysis are commonly employed geochemical techniques that offer concise insights into kerogen type, effective source-rock identification and thermal maturity. In the current study, the data obtained from Rock-Eval pyrolysis has been used to define the source-rock quality, generative potential, kerogen type, maturity of the source sediments and kerogen kinetics of the Baisakhi–Bhadesar Formation of Kimmeridgian–Tithonian (154.7–145.6 Ma) age. Basinal level hydrogen index (HI), TOC content, source-rock maturity, transformation ratio and heat-flow maps have been generated by integrating the data from pyrolysis with previously available data from wells drilled in the basin. The TOC content of the Kimmeridgian–Tithonian sequence ranges from 0.03 to 12.71% in the studied samples, with an average TOC content of 1.28%, indicating good source-rock quality. The HI, in collaboration with T max and vitrinite reflectance (VR o ) data, demonstrates that the Baisakhi–Bhadesar Formation is characterized by type II, a mixture of type II/III and type III kerogen facies and exhibits good source-rock quality and poor to good generative potential in the basin. The studied samples are marginally mature to mature in nature ( T max , 430–450°C; VR o , 0.52–0.72%). A maturity analysis of the basin suggests that during the Late Jurassic most areas were under the oil window zone, except for the Bhakhari Tibba and Miajlar areas. The transformation ratio overlay for the Kimmeridgian–Tithonian source sequences shows better transformations of the source rock in the area of the Shagarh Sub-basin. Kerogen kinetics of the studied Baisakhi–Bhadesar Formation demonstrate that the activation energy ranges between 46 and 74 kcal mol −1 with the significant distribution of activation energy being 54 kcal mol −1 (42.07%), representing a strong heterogeneous type of organic matter in the sediments. Based on lithological, palaeontological and electrolog studies, a shallow-marine to nearshore environment of deposition with a sediment-input direction from the SE has been inferred for the Kimmeridgian–Tithonian sequences. The results of this study quantitatively establish the role of the Kimmeridgian–Tithonian sequence as a source rock, ultimately contributing to the generation of hydrocarbons in the basin along with spatial changes in the quality of source sediments in different parts of the basin.

ОГЛЯД ВІЗЕЙСЬКИХ КОЛЕКТОРІВ НЕТРАДИЦІЙНОГО ТИПУ ДНІПРОВСЬКО-ДОНЕЦЬКОЇ ЗАПАДИНИ ТА ПОРІВНЯННЯ З ПІВНІЧНОАМЕРИКАНСЬКИМИ НЕТРАДИЦІЙНИМИ ФОРМАЦІЯМИ

Background. Modern advances in the extraction of hydrocarbons from shale and tight formations, namely improved horizontal drilling technologies and multi-stage hydraulic fracturing at economically viable costs, are opening up new horizons for oil and gas exploration and development around the world. The importance of shale oil and gas has sparked interest around the world following the great success of production in North America. This article is a continuation of a series of publications on the study of Visean unconventional reservoirs within Dnipro-Donets Depression. In this paper, the Visean sediments, namely the Lower Visean carbonate plate of the XIII MFH (horizons V-24-25), and the "Rudov Beds", siliceous calcified organic-rich shales (V-23) within the identified prospective zones of the Dnipro-Donets Basin (DDB), are considered for their unconventional reservoir development potential using the method of analogy with successful North American formations. Methods. Key geological and geochemical parameters were compared with the selected analogues, namely, geological age, sedimentation conditions, lithology and sediment thickness, geochemical data (total organic carbon (TOC), vitrinite reflectance (Ro), rock generation properties according to pyrolytic studies and rock maturity), mineralogical composition and porosity. Results. According to this study, the Visean unconventional deposits within DDB clearly correlate with the most productive gas fields from unconventional reservoirs (shales, organic-rich carbonates) in North America. The depth and geological position of the Visean unconventional targets are generally comparable to or slightly higher than their North American counterparts based on available data; sediment thicknesses are in similar ranges. In terms of mineralogical composition, namely X-ray diffraction (XRD) analysis, the ore beds are similar to the Barnett and Woodford shales, and the V-24-25 carbonate horizons correspond to the Eagle Ford Formation. The high average TOC content of the V-23 horizon (up to 10% by weight) is comparable to the Bakken and Woodford shales. Сonclusions. The geological and geochemical parameters of the Visean horizons considered in this paper are promising in terms of the prospects for the development of unconventional reservoirs to increase Ukraine's energy resource base. However, in order to draw conclusions about the economic profitability of the development of the studied objects, a more detailed study is required, taking into account the results of drilling and testing after multistage hydraulic fracturing.

Gas source of the Middle Jurassic Shaximiao Formation in the Zhongjiang large gas field of Western Sichuan Depression: Constraints from geochemical characteristics of light hydrocarbons

The Zhongjiang gas field is a typical large gas field in terrigenous strata of the Western Sichuan Depression. It remains debatable which member of the Upper Triassic Xujiahe Formation served as the source rocks and how significant the member contributed to the gas accumulations in the Zhongjiang gas field. In this study, we analyzed the essential characteristics of the Lower Jurassic source rocks and the geochemical features of light hydrocarbons in natural gas from the 2nd (T3x2) and 4th members (T3x4) of the Upper Triassic Xujiahe Formation (T3x), as well as the Middle Jurassic Shaximiao (J2s) and Qianfoya (J2q) formations. Based on this, we explored the sources of the natural gas in the Zhongjiang gas field and determined the natural gas migration patterns and their effects on the properties of light hydrocarbons in the natural gas. The results indicate that the Lower Jurassic lacustrine source rocks of the Zhongjiang gas field contain humic organic matter, with vitrinite reflectance (Ro) values ranging from 0.86% to 0.98%. Samples meeting the criterion for effective source rocks [total organic carbon (TOC) content ≥0.75%] exhibited an average TOC content of merely 1.02%, suggesting significantly lower hydrocarbon generation potential than source rocks in the underlying T3x, which show higher thermal maturity and TOC contents. For natural gas samples from T3x2, T3x4, J2s, and J2q reservoirs, their C5–7 iso-alkane content was significantly higher than their n-alkane content, and their methylcyclohexane (MCH) index ranged from 59.0% to 77.3%, indicating the predominance of methylcyclohexane in C7 light hydrocarbons. As indicated by the origin identification and gas-source correlation based on the geochemical features of light hydrocarbons, the natural gas in the Zhongjiang gas field is typical coal-derived gas. The gas from the primary pay zone of the Shaximiao Formation, with significantly high K1, (P2 + N2)/C7, and P3/C7 values, predominantly originated from the 5th member of the T3x and migrated in the free phase, with a small amount possibly sourced from the Lower Jurassic source rocks. The dissolution and adsorption during gas migration led to a decrease in the aromatic content in C6–7 light hydrocarbons and an increase in the iso-heptane values. Therefore, their effects must be considered when determining the gas origin and thermal maturity based on the aromatic content in C6–7 light hydrocarbons and iso-heptane values.

Long-Term Application of Manure and Different Mineral Fertilization in Relation to the Soil Organic Matter Quality of Luvisols

Long-term field experiments were conducted on luvisol at five sites in the Czech Republic (42–48-year duration). The average total organic carbon content in the soil varied between 9.0 and 14.0 g kg−1. In these trials, seven crops were rotated in the following order: clover, winter wheat, early potato, winter wheat, spring barley, potato, and spring barley with interseeded clover. Five treatments were studied: unfertilized treatment (Con), farmyard manure (F), and combinations of farmyard manure with three mineral fertilization levels (F+M1, F+M2, F+M3). Plant residues were not incorporated into the soil. An amount of 40 t ha−1 of farmyard manure fresh matter was applied twice during crop rotation. Intensive mineral fertilizer (F+M3) increased the average value of the carbon sequestration efficiency (CSE) by 12.9% and up to 26.3%. Combining organic and mineral fertilizers at moderate and higher intensities increased the soil organic matter quantity and quality compared to the unfertilized or manure treatment. Data on the glomalin content can be used to study the organic matter quality. We determined a strong correlation between the total glomalin content and the soil organic matter carbon, fulvic acid content, humic acid content, extractable carbon content, and dissolved organic carbon content, as well as the potential wettability index and aromaticity index.

Organic petrography and geochemistry of the Fu 2 member of the Paleocene Funing formation, Gaoyou Depression, Subei Basin, Eastern China: Implications for shale oil potential

The Fu 2 Member of the Paleocene Funing Formation in the Gaoyou Depression, Subei Basin is an organic matter-rich formation, and has a high potential for shale oil exploration and exploitation. Total organic carbon (TOC), organic petrography, Rock-Eval pyrolysis, chloroform bitumen “A” extraction, and SARA (saturates/aromatics/resins/asphaltenes) composition analyses of shale samples from one drill core in the studied area spanning a thickness of 257 m were conducted to study the organic matter (OM) richness, kerogen type, maceral composition, hydrocarbon generation potential, and oil content of the Fu 2 Member. Results show that the Fu 2 Member shales in the study area have a Ro of 0.87%, in the peak oil window, suggesting a high potential for hydrocarbon generation. The studied OM in shales mainly belongs to kerogen Type II, with a minor portion of Type I and Type III. Under microscopic observation, macerals in the studied shales are mainly composed of vitrinite, inertinite, alginite, and solid bitumen. The studied shales have an average TOC content of 1.41 wt%, indicating good petroleum potential. The variations of maceral compositions could affect the reliability when the Tmax is used as an indicator of thermal maturity. The lower Shale 4 and upper Shale 5 interval (3650–3700 m), with high TOC and high oil saturation index, is identified as the sweet-spot interval of the Fu 2 Member for shale oil exploration.

Geological Characteristics and Controlling Factors of Shale Gas in the Permian Shanxi Formation, the Southern North China Basin

Abstract Energy resources exploration has been taking place in the Southern North China Basin (SNCB) for decades, but no big breakthroughs have been made. A case study focusing on the Lower Permian Shanxi Formation in the Taikang Uplift of the SNCB is presented in this paper; based on the practice of shale gas exploration, we summarize the geological characteristics, geochemical characteristics, mineral characteristics, and pore type and analyze the exploration potential shale gas. The type of organic matter in the studied strata is mainly type III, the vitrinite reflectance (Ro) is between 2.1% and 3.4%, the average total organic carbon content is 1.66%, the mineral of shale is mainly composed of quartz and clay, and the main reservoir space types are mineral pores and microfractures. Through comprehensive evaluation, the sedimentary environment, organic matter abundance, physical properties, and mineral composition control the shale gas accumulation in the studied area.

Geological Characteristics of Shale Reservoir of Pingdiquan Formation in Huoshaoshan Area, Junggar Basin

Unconventional oil and gas, represented by shale gas and shale oil, have occupied an important position in global energy. The rapid growth of shale gas and shale oil production shows great potential for the exploration and development of shale resources. Junggar basin, the main oil-bearing basin in China, is rich in oil and gas resources, so it is of great practical significance to carry out systematic research on the geological characteristics of shale reservoirs in this region. To this end, this paper designates the shale reservoir of Pingdiquan Formation in Huoshaoshan area of the Jungar Basin as the research object, carries out a geological survey in that area, analyzes reservoir forming conditions using the geological interpretation method, analyzes different local trap reservoir types and their main control factors by dissecting the explored reservoir, optimizes and evaluates favorable traps using the source, fault, facies and circle coupling analysis method, establishes single good identification standard of sedimentary microfacies, and carries out well-connected sedimentary microfacies analysis. Using geochemical methods, such as rock pyrolysis, maceral analysis, vitrinite reflectance, kerogen carbon isotope, saturated hydrocarbon chromatography, etc., the abundance and types of organic matter of shale in different intervals are analyzed and the geological characteristics of shale reservoirs are evaluated. This paper aims to analyze the oil and gas content of the shale reservoir in Pingdiquan Formation in the Junggar Basin to provide reliable reservoir evaluation and guide better development of shale oil and gas resources in the future. The innovative expenditure of this paper lies in conducting the research from two aspects: the analysis of the main controlling factors of reservoir formation from the structural point of view and the analysis of the pore structure and geochemical characteristics of shale from the core experiment point of view, and also the classification of organic matter, so as to provide a basis for finding favorable traps. The results show that the shale sedimentary system in the study area is a small fluvial delta, which belongs to a compression structure, with developed NNE-oriented structural belts and faults; the structural form is a short-axis anticline as a whole, forming a structural coil closure at −900 m, with a trap area of 50 km2 and a closure height of 180 m. According to the geological interpretation method, 19 faults of all levels were found in the area and the vertical migration conditions of oil and gas were good. Pingdiquan Formation was oil-bearing, with many vertical oil-bearing strata and strong horizontal independence of the reservoir. The sedimentary thickness of the Permian Pingdiquan Formation in the study area is 300~1200 m and the oil-bearing strata are divided into 3 oil-bearing formations, 9 sublayers, and 22 monolayers from top to bottom. The abundance of organic matter in different strata is generally high, with an average total organic carbon content of 3.53%, an average hydrocarbon generation potential of 18.1 mg/g, an average chloroform asphalt content of 0.57%, and an average total hydrocarbon content of 3011 μg/g, all of which belong to the shale standard, especially Ping-2. The organic matter in different layers belongs to types I-II1, and the organic matter types are I-II1, I-II2, and II1-II2, respectively. The average carbon isotope of shale kerogen is −2.4%, which belongs to type II2 kerogen.

Geochemical Characteristics and Evaluation Criteria of Overmature Source Rock of the Laiyang Formation in Well LK-1, Riqingwei Basin, Eastern China

Total organic carbon (TOC) and hydrocarbon generation potential (Pg) are essential parameters for the qualitative evaluation of source rock and the basis for evaluating hydrocarbon resources in petroliferous basins. However, there will be some deviations in evaluating hydrocarbon resources of overmature source rock by using TOC and Pg. The super-thick overmature source rock of the Early Cretaceous Laiyang Formation was found in well LK-1, the Riqingwei Basin. To accurately understand the oil and gas potential of the Riqingwei Basin, this paper conducted a systematic organic geochemical analysis of the overmature source rock of the Early Cretaceous Laiyang Formation found in well LK-1. Combined with the results of previous thermal simulation tests on hydrocarbon generation of low-maturity samples in the Jiaolai Basin, the original total organic carbon (TOC0) content of source rock in well LK-1 was recovered and the evaluation criteria of overmature source rock was established. Results: (1) The average TOC content of well LK-1 source-rock samples is 1.25 wt.%, and the average Pg content is 0.11 mg/g. The type of organic matter is mainly type II2, including a small amount of type II1 and type III. The average reflectance of vitrinite (Ro) is 4.35%, which belongs to overmature source rock of a poor–fair level and mixed kerogen. (2) After recovery calculation, these samples’ original hydrocarbon generation potential (Pg0) contents ranged from 0.63 to 108.1 mg/g, with an average value of 6.76 mg/g. Furthermore, the TOC0 contents of the analyzed source-rock samples ranged from 0.62 to 30.6 wt.%, with an average value of 2.01 wt.%. It belongs to fair–good source rock, showing better hydrocarbon generation potential. (3) According to the relationship between the Pg0, Pg and TOC content, the evaluation standard for overmature source rock in well LK-1 was established. Under the evaluation standard of overmature source rock, a source rock with a TOC content exceeding 0.6% and a Pg content greater than 0.1 mg/g can be identified as a good source rock. This paper provides a foundation for the fine classification and evaluation of the overmature source rock of the Riqingwei Basin.

Paleoenvironment Evolutionary Characteristics of Niutitang Shale in Western Hubei, Middle Yangtze, China.

The black shale developed in the first section of the Niutitang formation (ϵ1n1) is one of the most important shale gas reservoirs in western Hubei, and its geological characteristics have been sufficiently studied by many predecessors. However, there are still three aspects that need further research: the origin of silicon, the discrimination of the euxinic sulfuretted and the anoxic ferruginous conditions, and the main controlling factors of organic matter enrichment. Based on geochemical data from well ZD1 located in the city of Yichang in western Hubei, first, the geochemical characteristics of ϵ1n1 are analyzed, then the provenance, depositional site, and paleoenvironment evolution are discussed, and finally, the main controlling factor of organic matter enrichment is revealed. The results show that ϵ1n1 can be divided into two units, organic-rich shales (ORS) and organic-lean shales (OLS), which have average total organic carbon contents of 4.21 and 0.84%, respectively. Additionally, the ORS is characterized by high contents of SiO2, U, V, Ni, Zn, and Cu and left-inclining types of rare earth element distribution curves. ϵ1n1 is located in a passive continental margin with a material source mainly from mixed felsic and mafic rocks. Compared with the OLS, the content of biological quartz is much greater, and the terrigenous input is less in the ORS. The paleoclimate is cold and humid with low salinity in the ORS, whereas it is hot and dry with high salinity in the OLS. ϵ1n1 is deposited in a semistagnant basin, and the ORS shows a relatively lower stagnant degree with euxinic to anoxic conditions and moderate to high paleoproductivity, while the OLS shows a high stagnant degree with suboxic to oxic conditions and lower paleoproductivity. The redox conditions are the main controlling factors affecting organic matter enrichment. The environmental evolution model with three stages shows that there is a good causal relationship between redox conditions, paleoproductivity, and sea level fluctuation. The black carbonaceous siliceous in the lower part of the ORS with a thickness of approximately 40 m is the most favorable layer, which will provide a theoretical basis for further shale gas exploration of ϵ1n1 in the western Hubei.

Potential resources of conventional, tight, and shale oil and gas from Paleogene Wenchang Formation source rocks in the Huizhou Depression

Conventional and tight unconventional oil and gas resources in the Huizhou Depression have shown broad exploration prospects, which mainly originate from Wenchang Formation source rocks. Thus far, studies on Wenchang Formation source rocks mainly focused on the geochemical characteristics and conventional petroleum resource evaluation; however, the correlation of conventional, tight, and shale oil and gas, and their resources are still unknown. In fact, the formation of conventional, tight, and shale oil and gas are intrinsically related, which allows for a more objective evaluation to consider the three types of oil and gas resources simultaneously in the whole dynamic process of both hydrocarbon generation and expulsion, as well as reservoir tightness history. In this work, based on geological and geochemical analyses, the improved hydrocarbon generation potential method was utilized to establish a hydrocarbon generation and expulsion model of the Wenchang Formation source rocks. Then, combined with the reservoir tightness history, the conventional, tight, and shale oil and gas resources were evaluated. The results show that the Wenchang Formation source rocks are distributed in the whole depressions, with a thickness of 50-1850 m and an average total organic carbon content of 2.2%. The organic matter is mainly type II and is mature-high maturity. The Wenchang Formation source rocks reached hydrocarbon generation threshold and expulsion threshold at a vitrinite reflectivity of 0.43% and 0.65%, respectively, and the reservoir evolved completely tight at 2.3 Ma. Overall, the Lower and Upper Wenchang Formation contain a large amount of conventional, tight, and shale oil and gas resources. Cited as: Hu, T., Wu, G., Xu, Z., Pang, X., Liu, Y., Yu, S. Potential resources of conventional, tight, and shale oil and gas from Paleogene Wenchang Formation source rocks in the Huizhou Depression. Advances in Geo-Energy Research, 2022, 6(5): 402-414. https://doi.org/10.46690/ager.2022.05.05

Shale Lithofacies and Sedimentary Environment of the Third Member, Shahejie Formation, Zhanhua Sag, Eastern China

AbstractResearches into shale lithofacies, their sedimentary environments and relationship benefit understanding both of sedimentary cycle division and unconventional hydrocarbon exploration in lacustrine basins. Based on a 100∼300‐m‐thick dark shale, mudstone and limestone encountered in the lower third member of the Eocene Shahejie Formation (Es3l member) in Zhanhua Sag, Bohai Bay Basin, eastern China, routine core analysis, thin sectioning, scanning electron microscopy (SEM), mineralogical and geochemical measurements were used to understand detailed facies characterization and paleoclimate in the member. This Es3l shale sediment includes three sedimentary cycles (C3, C2 and C1), from bottom to top, with complex sedimentary characters and spatial distribution. In terms of the composition, texture, bedding and thickness, six lithofacies are recognized in this succession. Some geochemical parameters, such as trace elements (Sr/Ba, Na/Al, V/Ni, V/(V + Ni), U/Th), carbon and oxygen isotopes (δ18O, δ13C), and total organic carbon content (TOC) indicate that the shales were deposited in a deep to semi‐deep lake, with the water column being salty, stratified, enclosed and reductive. During cycles C3 and C2 of the middle‐lower sections, the climate was arid, and the water was salty and stratified. Laminated and laminar mudstone–limestone was deposited with moderate organic matter (average TOC 1.8%) and good reservoir quality (average porosity 6.5%), which can be regarded as favorable reservoir. During the C1 cycle, a large amount of organic matter was input from outside the basin and this led to high productivity with a more humid climate. Massive calcareous mudstone was deposited, and this is characterized by high TOC (average 3.6%) and moderate porosity (average 4%), and provides favorable source rocks.

Depositional Paleo-Environments of Lower Cambrian Qiongzhusi Formation in the Western Middle Yangtze Block and Its Controlling Effect on the Organic Matter Enrichment

No systematic comparative study has been conducted on the factors controlling organic matter enrichment in the different depositional environments of the Lower Cambrian Qiongzhusi Formation in the western Middle Yangtze Block, leading to a large discrepancy in our understanding. Based on organic geochemical and elemental analyses of core, outcrop, rock, and mineral samples from the slope, deep-water shelf, and shallow-water shelf, in this study, comparative analysis of the organic matter content, sedimentological characteristics, and depositional paleoenvironments of the Lower Cambrian Qiongzhusi Formation in the western Middle Yangtze Block was conducted, and the main controlling factors and models of the organic matter enrichment were investigated. The results revealed that the organic matter enrichment in the Qiongzhusi Formation was jointly controlled by redox conditions, water restriction, upwelling currents, terrigenous inputs, and paleo-productivity, but the main factors controlling the enrichment during the different periods were significantly different. (1) During the deposition of the Qiong 1 Member, the extensional rifting was strong, and the sea level was always high. The low degree of terrigenous dilution and anoxic conditions favored organic matter preservation. In this period, the upwelling currents were the main factor controlling organic matter enrichment. The paleo-productivity decreased as the intensity of the upwelling currents gradually weakened from the slope to the shelf, leading to a decrease in the total organic carbon (TOC) content and thereby a gradual decrease in the biogenic silica content of the shale. (2) During the deposition of the Qiong 2 Member, the extensional rifting weakened, and the sea level continued to drop. The upwelling currents, terrigenous input, and redox conditions were all important factors controlling the organic matter enrichment in the region. From the slope to the shelves, the conditions favorable for organic matter enrichment gradually worsened, and the TOC content gradually decreased, with the lithofacies gradually transitioning from biogenic siliceous shale to clayey shale or clayey-calcareous shale. (3) During the deposition of the Qiong 3 Member, the Yangzi Platform underwent a filling and leveling-up process, and the redox conditions played a major role in controlling the organic matter enrichment. The entire region was dominated by an oxygen-rich environment, and the conditions were no longer favorable for organic matter preservation, leading to a low average TOC content. Overall, the spatial variability of the TOC content was closely associated with changes in the depositional paleoenvironment caused by sea-level changes.

Excellent source rocks found along the margin of a large lacustrine basin: Case study from the Ordos Basin, China

Whether the Chang 6 oil pools of the Triassic Yanchang Formation in the Ansai-Yanchang (AY) oil province on the Yishan slope of the Ordos Basin formed from near source rock or far source rock has long been debated. An understanding of the source rock's position will impact the formation mode and distribution of accumulations in this area. Based on the geochemical data of the Chang 7 source rock in six wells and 18 crude oil samples, the geochemical characteristics of Chang 7 source rock and its relationship with Chang 6 crude oil were studied. There are two types of source rocks, namely, black shales and dark mudstones, present in the AY area. The gross thickness of the Chang 7 black shale is 3.0–19.7 m, with a distribution area of 5500 km2. It has an average total organic carbon (TOC) content of 3.34%, with a chloroform bitumen “A" content of 0.512%, indicating good to excellent source rock potential. The kerogen assessment with core samples shows mixed type I-II1, and has reached peak oil generation, maximum pyrolysis temperatures (Tmax) ranging from 445 to 458 °C. In contrast, the average TOC content of the dark mudstone in Chang 7 is 0.91%, chloroform bitumen “A” is 0.079%, the main type of kerogen is type II2-II1, and Tmax varying from 446 to 461 °C, indicating only fair source rock potential overall. The Chang 7 source rocks in the AY area have a gammacerane index of 0.07–0.38, with an average value of 0.21, which reflects a low-salinity fresh to brackish water environment. The relative abundances of C27, C28, and C29 steranes are 29.7%, 23.1% and 47.2%, respectively, indicating that terrestrial higher plants and aquatic organisms provide similar contribution in the Chang 7 source rocks. Oils produced from the AY area of the Chang 6 member have similar geochemical signatures, but are significantly different from the Chang 6 crude oils in the Daozhen (DZ) area of Ganquan County and the Huaishuzhuang (HSZ) area of Fuxian County, which are located in the center of the lacustrine basin. They differ in terms of the maturity of the oil samples and the microscale composition of the parent material type. The closer the wells are to the center of the lacustrine basin, the higher the maturity of the source rock and the greater the contribution of aquatic organisms. The variation of carbon isotopic composition of Chang 6 crude oil in AY area is consistent with that of Chang 7 shale locally, but opposite to that of Chang 6 crude oil in DZ area. The ratios of nC21-/nC22+, tricyclic terpane/hopane and C29 sterane ββ/(ββ+αα) biomarker parameters of Chang 6 crude oils in AY area are similar to those of Chang 7 shale in local area, but deviate from those of DZ and HSZ area. These data results reveal that the Chang 6 crude oils in the AY oil province are dominated by the local Chang 7 excellent source rocks rather than by the long-distance migration of oils from the basin center.

Pore Structure and Wettability of Lacustrine Shale With Carbonate Interlayers in Dongying Depression, Bohai Bay Basin, East China

Shale samples with carbonate interlayers have attracted more and more attention in shale oil exploration of lacustrine shale in China, and the characterization of pore structure and wettability of these shales are significant to the study of shale-oil enrichment and effective exploitation. In this work, by examining six shale samples with carbonate interlayers of Shahejie Formation in East China, the pore structure and wettability characteristics of shale are characterized by means of thin section petrography; X-ray diffraction mineralogy; total organic carbon (TOC) analyses; scanning electron microscopy (SEM) imaging; air-liquid contact angle for wettability; as well as N2 physisorption, mercury intrusion porosimetry, and nuclear magnetic resonance (NMR) for pore structure. The results show that the main mineral contents are carbonate (with an average of 51.4%) and clay minerals (mainly mixed-layer illite-smectite). The average TOC content is 2.90%, and there is a strong correlation between TOC and dolomite content. In addition, the obvious layered structure is observed by thin section and SEM methods. The pores below 200 nm with ink-bottle shapes are obviously smaller than those of marine shale, and the pore throats are mainly below 50 nm; however, there are also some micrometer-sized cracks. The droplet contact angle measurement shows that the shale is mainly lipophilic, while moderately hydrophilic, at millimeter observational scales. The NMR T2 spectra of water- and oil-saturated samples have an obvious feature of three peak characteristics, as the pore size-associated wettability of these samples can be divided into three stages: water-wet (0.01–1 ms), oil-wet (1–40 ms), and mixed-wet (>40 ms) in terms of relaxation time of the NMR T2 spectrum. The proportion of the second main peak of T2 spectra (P2) for dodecane-saturated samples is directly proportional to the TOC content, and the relationship between P2 and mineral composition is consistent with water-saturated samples.

Geochemical Characteristics and Their Marine Environmental and Organic Source Implications for the Lower Cambrian Shales in Guizhou Province, South China

Abstract In this study, we conducted systematic analysis of total organic carbon (TOC) content, lipid biomarkers, carbon isotopes of kerogen (δ13Ckerogen), and mineral composition in Niu-ti-tang (Є1n) and Pa-lang (Є1p) shales from Guizhou Province in order to provide a better understanding of the organic sources and marine environmental condition during deposition of the Lower Cambrian shales of South China. The results show that a broad variety of lipid biomarkers, such as n-alkanes, pristane, phytane, terpanes, hopanes, and steranes, are in these shales, which suggests a significant contribution of various paleobios with bacterial microorganisms and algae thriving under a low-salinity and stable anoxic environment. The negative δ13Ckerogen value (minimum −36.4‰) and occurrence of pyrite (1–7.5%) and carbonates (2.4–57.3%) indicate that bacterial sulfate reduction prevailed under anoxic conditions during deposition of the Lower Cambrian shales. Moreover, the difference in mineral and δ13Ckerogen composition between Є1n and Є1p shales might imply significant changes in primary production and paleoocean environments due to sea-level rise, as shown by the higher average TOC content in Є1p shales (2.52%) compared to that in Є1n shales (1.79%). The covariances of TOC content and mineral and δ13Ckerogen composition suggest that the Є1p shales might have been deposited under a higher sea level associated with high primary productivity, compared to Є1n shales. Thus, high primary productivity driven by sea-level rise is suggested to be the main controlling factor on organic matter enrichment in Є1p shales under stable anoxic conditions.

Influence of the Duration of Tectonic Evolution on Organic Matter Pore Structure and Gas Enrichment in Marine Shale: A Case Study of the Lower Silurian Longmaxi Shale in Southern China

The exploration and development of the shale in the Lower Silurian Longmaxi Formation in the Chongqing area has shown that gas production here is commercially viable. In contrast, the Longmaxi Formation shale in Hunan shows that gas production is not commercial. Why is there such a difference between the Chongqing and Hunan areas for the same formation. A mount of previous studies showed that gas is stored primarily in the organic matter (OM) pores in shale. This study has investigated the Longmaxi shale from two well locations in Chongqing and Hunan in order to understand whether differences in pore structure are the cause of the difference in commerciality in the two areas. The formation burial histories were established, analyzing samples for mineral composition, total organic carbon (TOC) content, thermal maturity (Ro), and OM pore structures. The results show that the Longmaxi shale in Chongqing and Hunan has similar TOC content and Ro. The average TOC content is above 3.0% for samples from both areas, and the thermal maturity was all between 2.4 and 2.9%. OM pores of the Longmaxi shale in Chongqing are abundant in number and relatively large sized, with mostly circular and oval shapes. In contrast, the number and size of the OM pores in the Longmaxi shale in Hunan are small, and the shape is irregular. OM pore structure of the Longmaxi shale in Chongqing is therefore favorable for preservation of gas. The poor pore structure of the Longmaxi shale in Hunan is not conducive to gas preservation. The OM pore structure difference of the Longmaxi shale in Chongqing and Hunan is determined by the formation burial history. The Longmaxi shale in the Chongqing area experienced rapid burial in the Early Jurassic and rapid uplift in the Late Cretaceous. The Longmaxi Formation in Hunan experienced rapid burial in the Early Triassic and rapid uplift in the Early Jurassic. The long evolution time (100 Ma) of the Longmaxi shale in Chongqing produced a large amount of gas supply and enough storage space (OM pores) for the gas occurrence, which makes the amount of gas be preserved in geological history. The short evolution time (50 Ma) of the Longmaxi shale in Hunan produced insufficient gas supply and not enough OM pores in reservoir, which leads to gas loss in geological history, resulting in low gas content. Therefore, to evaluate the potential of shale gas, the evolution time of organic matter must be considered. In other words, the time interval between rapid subsidence and uplift of formation during geological history must be considered.

Depositional Setting and Enrichment Mechanism of Organic Matter of Lower Cretaceous Shale in Ri-Qing-Wei Basin in the Central Sulu Orogenic Belt

A suite of source rock consists of mudstone and shale, with great thickness and continuous deposition was found in the well LK-1 in Lingshan island in Ri-Qing-Wei basin. In order to evaluate the hydrocarbon generation prospects of these source rock and find the mechanism of organic matter enrichment, shale samples were selected from the core for TOC (total organic carbon) and element geochemistry analysis. The results show that organic matter abundance of the source rocks are generally high with average TOC content of 1.26 wt%, suggesting they are good source rocks. The geochemical features show that the sedimentary environment is mostly anoxic brackish water to salt water environment with arid to semiarid climate condition. The enrichment mechanism of organic matter varied with the evolution of the basin, which was divided into three stages according to the sedimentary characteristics. In the initial-middle period of rifting evolution (stage 1 and early stage 2), paleoproductivity is the major factor of OM-enrichment reflecting by high positive correlation between the TOC contents and paleoproductivity proxies. While with the evolution of the rift basin, redox condition and terrigenous clastic input became more and more important until they became the major factor of OM enrichment in the middle stage of rift evolution (stage 2). In the later stage of rift evolution (latest stage 2 and stage 3), besides terrigenous clastic input, the effect of paleoclimate on OM-enrichment increased gradually from a minor factor to a major factor.

Effect of paleoclimate and paleoenvironment on organic matter accumulation in lacustrine shale: Constraints from lithofacies and element geochemistry in the northern Qaidam Basin, NW China

Organic matter enrichment in lacustrine shale is significantly influenced by paleoclimate and paleoenvironment. In this study, a total of 24 shale samples were vertically collected from the YQ-1 drilling well in the northern Qaidam Basin, north-western China. The high-resolution geochemistry analyses were performed to provide a detailed geological description of these samples through lithofacies interpretation, total organic carbon (TOC) content testing, element geochemistry analysis, and mineralogical composition characterization. The results show that four lithofacies types can be identified in the Middle Jurassic Shimengou Formation, which consist of the brown oil shale with horizontal bedding, the black shale with well-developed lamination, the grey-black mudstone with horizontal and wavy bedding, and the carbonaceous mudstone with plant debris. The former two types were preserved in the Upper Member and were mainly deposited in a deep and semi-deep lake environment, whereas the latter two types were preserved in the Lower Member and were deposited in a littoral-shallow lake. The TOC content, paleo-salinity, redox action, and paleo-productivity of the shales in the Upper Member are higher than those in the Lower Member, and other parameters, such as the chemical weathering degree and terrestrial clastic input, are higher in the shales of the Lower Member. Based on lithofacies and geochemical data, the shales in the Lower Member were deposited in a small, shallow freshwater lake within an oxygen-rich and relatively wet and hot paleoclimate, whereas the shales in the Upper Member were deposited in a large, deep, and saline water lake with dysoxic-anoxic conditions and a relatively arid and cold paleoclimate. The organic matter content in the Lower Member was primarily determined by the amount of detritus input with a low paleo-productivity owing to a strong weathering, whereas that in the Upper Member was dominated by anoxic processes under a good preservation and a low deposition rate. The model reflecting the relationship between accommodation and sediment-fill is employed to analyse the mechanism of organic matter accumulation. Three depositional stages are distinguished within the Shimengou Formation corresponding to overfilled, underfilled, and balanced-filled sediments with average TOC contents of 0.84 %, 4.95 %, and 6.09 %, respectively. This study reveals the dominated factors controlling organic matter enrichment in a continental basin and proposes a TOC distribution mechanism, which could provide a guide for the shale gas and shale oil exploration. • High-resolution geochemistry and detailed geological description were performed. • Paleoclimate evolution of Middle Jurassic Shimengou Formation was analysed. • Detritus inputs and anoxic degree were predominant factors for influencing TOC. • Three depositional stages of the Shimengou Formation were subdivided. • The model of lacustrine organic matter accumulation was proposed.

Multimineral petrophysics of thermally immature Eagle Ford Group and Cretaceous mudstones, U.S. Geological Survey Gulf Coast 1 research wellbore in central Texas

Traditional petrophysical methods to evaluate organic richness and mineralogy using gamma-ray and resistivity log responses are not diagnostic in source rocks. We have developed a deterministic, nonproprietary method to quantify formation variability in total organic carbon (TOC) and three key mudrock mineralogical components of nonhydrocarbon-bearing source rock strata of the Eagle Ford Group by developing a set of log-derived multimineral models calibrated with Fourier transform infrared spectroscopy core data from the research borehole U.S. Geological Survey Gulf Coast 1 West Woodway. We determined that bulk density response is a reliable indicator of organic content in these thermally immature, water-bearing source rocks. Multimineral findings indicate that a high degree of laminae-scale mineralogical heterogeneity exists due to thinly interbedded carbonate cements amid clay-rich mudstone layers. The lower part of the Eagle Ford Group contains the highest average TOC content (4.7 wt%) and the highest average carbonate volume (64.1 vol%), making it the optimal target in thermally mature areas for source-rock potential and hydraulic-fracture placement. In contrast, the uppermost portion of the Eagle Ford Group contains the highest average volume of clay minerals (42.6 vol%), which increases the potential for wellbore stability issues. Petrophysical characterization reveals that porosity is approximately 30% in this relatively uncompacted formation. In this thermally immature source rock, water saturation is nearly 100% and no free hydrocarbons were observed on the resistivity logs. No evidence of borehole ellipticity was observed on the three-arm caliper log, and horizontal stresses are presumed to be directionally uniform in the vicinity of this near-surface wellbore. This shallow wellbore has a temperature gradient of 1.87°F/100 ft (16.3°C/km) and is likely influenced by earth surface heating.

Distribution and Sources of Organic Carbon in Surface Intertidal Sediments of the Rudong Coast, Jiangsu Province, China

In this study, total organic carbon (TOC), total nitrogen (TN), and stable carbon isotopes (δ13C) were measured in surface intertidal saltmarsh and bare tidal flat sediments along the Rudong coast. The distribution and sources of organic carbon were examined under different depositional environments based on C/N ratios and a two-terminal mixing model. The results showed that the average TOC content of the vegetated saltmarsh sediments, bare tidal flat areas near vegetation (BF1), and bare tidal flat areas far from vegetation (BF2) were 4.05, 2.72, and 1.22 mg/g, respectively. The mean δ13C value within the vegetated saltmarsh area was −22.37‰, and the C/N ratio was 9.3; the corresponding values in the BF1 area were −23.27‰ and 7.95, respectively; and in the BF2 area, the corresponding values were −21.91‰ and 5.36, respectively. These C/N ratios reflect an increasing marine contribution with distance from the vegetated zone. Combined with the two-terminal mixing model, the organic carbon in the vegetated saltmarsh sediments was dominated by terrestrial sources, while the bare tidal flat sediments were more influenced by marine sources, and the bare tidal flat sediments nearer to the vegetated zone (BF1) were influenced by a combination of vegetation, marine sources, and other terrestrial factors.