Very Low‐Grade Metamorphism and Paleogeothermal Recovery of the Upper Palaeozoic in the Suhongtu Depression, Yin‐E Basin, North China: Constraints From Illite, Vitrinite Reflectance, and Fluid Inclusions

<p>Evaporitic salt is prevailed in marine sedimentary basins, and the discovered hydrocarbon reservoirs are generally associated with salt structures in the world; accordingly salt structures have attracted much attention from academic and industry during the past decade. Tarim Basin that locates in northwest China, is the largest marine sedimentary basin in China with great hydrocarbon resources potential. Previous studies of salt structures in this basin mainly focus on its strong sealing capacity and structural traps created by salt structures. However, besides its extreme impermeability and low viscosity, rock salt has another unique thermal properties, featured by a large thermal conductivity as high as 5~6 W/(m.K), usually 2~3 times greater than that of other common sedimentary rocks, but a relatively low radiogenic heat production. This strong contrast in thermal properties could change the evolving thermal regime and associated thermal history of the source rocks around salt bodies, but has not been understood well. Herein based on the theoretical models and interpreted salt bearing seismic profiles from the Kuqa Foreland Basin, northern Tarim Basin, we use the 2D finite element numerical experiments to investigate the impacts of salt structures on basin geothermal regime and associated hydrocarbon thermal evolution. Our results show that, owing to its high efficiency in heat conduction, the salt rocks would result in obviously positive temperature anomalies (3~13%) above the salt body and negative temperature anomalies (11~35%) in the subsalt, enhancing and restraining the thermal maturation of source rocks above and below the salt body, respectively. The amplitude and extent of geothermal effects of salt structures depend on the thermal conductivity, geometry, thickness and burial depth of the salt bodies. The thermally affected area around the salt body can be 2 time of salt radius laterally and 2~3 times of salt thickness vertically. Salt structures in the Kuqa Foreland Basin can prominently cool the subsalt formation temperature and accordingly reduce the thermal maturity (Ro) of Jurassic source rocks as much as 18%, enabling the source rocks to be still of gas generation other than over-mature stage as expected previously, which is favor for deep hydrocarbon preservation below salt. In particular, salt structures in the west and east Kuqa Foreland Basin show strong differences in their thickness, geometric pattern, burial depth and composition, the thermal effects of salt structures on thermal maturation of subsalt source rocks should differ accordingly, which is supported by the observed tempo-spatial variation of Ro for Jurassic source rocks in this basin. Finally, we propose that the geothermal effects of salt structures will be of great importance in the deep hydrocarbon resources potential assessment and exploration in marine sedimentary basins in China.</p>

The identification of the origin and source of natural gas is always a difficult and hot issue. Hereinto, the maturity identification is one of the most important scientific problems. Many empirical equations have been established to decipher the relationship between the maturity of gas source rocks and the carbon isotopic composition of natural gas. However, these equations proposed often fail to identify the maturity of the source rocks correctly, which in turn prevents the identification of genetic types and source rocks of the natural gas because the petroliferous sedimentary basins in China are complex and diverse, with multiple sets of source rocks and different thermal history. In this paper, the oil-associated gas from the Permian lacustrine source rocks and the coal-derived gas from the Jurassic source rocks in Junggar and Turpan-Hami basins have been investigated to decipher the relationship between the maturity (vitrinite reflectance) of gas source rocks and the carbon isotopic composition of methane. The equations established are δ13C1=25lgRo−42.5 for oil-associated gas, and δ13C1=25lgRo−37.5 for coal-derived gas. These new equations are suitable for the maturity identification of source rocks in most petroliferous basins, and favorable for the identification of the genetic type and source of natural gas, which is very important to improve the geological theory of natural gas.

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

Evaporitic salt is prevalent in marine sedimentary basins, and many discovered hydrocarbon reservoirs are generally associated with salt structures in the world; accordingly salt structures have attracted much attention from academia and industry during the past decade. The Tarim Basin, located in northwest China, is the largest marine sedimentary basin in China with great hydrocarbon resource potential. Previous studies of salt structures in this basin mainly focused on its strong sealing capacity and structural traps created by salt structures. However, besides its extreme impermeability and low viscosity, rock salt has other unique thermal properties, including a large thermal conductivity as high as 5–6 W/(m K), usually 2–3 times greater than that of other common sedimentary rocks, but a relatively low radiogenic heat production. This strong contrast in thermal properties could change the evolving thermal regime and associated thermal history of the source rocks around salt bodies, but it has not been understood well. Herein based on the theoretical models and interpreted salt-bearing seismic profiles from the Kuqa Foreland Basin, northern Tarim Basin, we use 2D finite element numerical experiments to investigate the impacts of salt structures on the basin geothermal regime and associated hydrocarbon thermal evolution. Our results show that, owing to their high efficiency in heat conduction, the salt rocks would result in obviously positive temperature anomalies (3%–13%) above the salt body and negative temperature anomalies (11%–35%) in the subsalt, enhancing and restraining the thermal maturation of source rocks above and below the salt body, respectively. The amplitude and extent of geothermal effects of salt structures depend on the thermal conductivity, geometry, thickness and burial depth of the salt bodies. The thermally affected area around the salt body can be 2 times the salt radius laterally and 2–3 times the salt thickness vertically. Salt structures in the Kuqa Foreland Basin can prominently cool the subsalt formation temperature and accordingly reduce the thermal maturity (Ro) of Jurassic source rocks as much as 18%, enabling the source rocks to stay in the range of gas generation rather than reaching an over-mature stage as expected previously; this situation is favorable for deep hydrocarbon preservation below salt. Because the salt structures in the west and east Kuqa Foreland Basin show strong differences in their thickness, geometric pattern, burial depth and composition, the thermal effects of salt structures on thermal maturation of subsalt source rocks should differ accordingly, which is supported by the observed temporal-spatial variation of Ro for Jurassic source rocks in this basin. Finally, we propose that the geothermal effects of salt structures will be of great importance in the deep hydrocarbon resources potential assessment and exploration in marine sedimentary basins in China.

Burial and thermal evolution of coal-bearing strata and its mechanisms in the southern North China Basin since the late Paleozoic

Review of natural origin, distribution, and long-term conservation of CO2 in sedimentary basins of China

Effect of volcanic activity on hydrocarbon generation: Examples in Songliao, Qinshui, and Bohai Bay Basins in China

The scope of the work presented in this paper is an evaluation of the petroleum potential of the source rock which shows most promise for the Barents Sea area. The evaluation is based on analysis of a large number of samples from a Middle Triassic black shale deposit on the various islands of the Svalbard Archipelago. This investigation has shown that the shale is an oil-prone source rock. Analysis of samples taken from areas in the Barents Sea, indicates that this shale sequence has similar potential as a source rock throughout the area south of Svalbard. Integration of this data with the available geophysical and geologica1 data allows us to propose that the rich, oilprone Middle Triassic shale sequence also has a widespread distribution throughout the Norwegian Arctic. The results of the geochemical analysis undertaken on Mesozoic deposits of Svalbard and from subsea outcrops in the Barents Sea area will be presented. In addition the significant geological data for the region will be included. The geochemical data to be discussed includes; total organic carbon content, Rock-Eval pyrolysis values, vitrinite reflectance and kerogen analysis in transmitted light. In addition some data on the amount and composition of extractable organic matter in the Triassic shales will be mentioned. Traditionally the Upper Jurassic shales have been regarded as the major source rocks on the Norwegian Continental Shelf. In addition to Jurassic source rocks there are some probable source rocks of Triassic age, particularly of Mid-Triassic age. Any oil and gas exploration in the Norwegian Arctic must take into account other possible source rocks from the Triassic, as well as those of Jurassic age which are regarded as the main source rocks in the North Sea. The presence of additional source rocks in the Barents Sea area increases the possibilities of oil and gas discoveries in this area. INTRODUCTION During the early stages of exploration for oil in the North Sea region there were lengthy discussions concerning the probable source rocks for the oil and gas, especially in the Northern North Sea. The geochemical techniques used in the late sixties and early seventies were rather crude and the errors introduced by this, at least in part, led to the conclusion that Paleocene shales were the source rock for the Ekofisk oi1 it was 1ater estab1ished that Ekofisk oil, as with other hydrocarbon accumulations found in the Central Graben (Fig. I), was sourced from the Upper Jurassic - Lower Cretaceous Kimmeridge Clay Formation. The situation in the Viking Graben (Fig. 1) is far more complex. It is generally accepted that most of the oil and gas found in the Norwegian sector of the North Sea has been sourced from shales of Jurassic age. Potential source rocks have been identified in shales from Upper, Middle and Lower Jurassic. In some areas potential source rocks have been identified in shales of Cretaceous and Lower Tertiary age, but it is believed that these are of minor importance.

In recent years, the exploration of oil and gas in China’s Precambrian strata has garnered significant attention, leading to notable advancements in exploration play assessment. However, there is a dearth of published literature on Proterozoic source rocks’ organic sources, sedimentary environments, marine hydrochemistry, and other attributes. This study focuses on investigating potential source rocks within the Hongshuizhuang and Xiamaling Formations in the Jibei Depression of North China. A comprehensive analysis was conducted to evaluate hydrocarbon generation characteristics, using hydrocarbon biomarkers and polar compounds as geochemical indicators for precursor biota and maturity levels. The results indicate high organic matter abundance with predominantly type I-II1 organic matter composition in the studied source rocks. These samples are at an immature–low mature stage, with the potential for primarily generating aromatic crude oil. The parent material is mainly attributed to lower aquatic organisms, such as bacteria and algae. The sedimentary environment exhibits marine facies, characterized by high evaporation rates, salinity levels, and strong euxinic conditions, that led to sulfur incorporation into the organic matter matrix. It should be noted that correlations between biomarker parameters and maturity may not be fully applicable to ancient source rocks; however, the methyldibenzothiophene ratio (MDR) demonstrates a strong correlation with Tmax. The compounds and their total monoisotope ions abundance (TMIA) were primarily identified and analyzed using FT–ICR MS. It was observed that these compounds were influenced by the depositional environment and organic matter maturity. Importantly, it was clearly demonstrated that the DBE and carbon number range of CH compounds gradually increased with maturity, due to the removal of N, S, and O functional groups. Specifically, N1 compounds predominantly consisted of carbazoles with short alkyl side chains which readily converted into N1Ox compounds. On the other hand, O1 compounds mainly comprised benzofurans with low abundance, indicating a reducing sedimentary environment, as suggested by their low TMIA values. Furthermore, S1 compounds were primarily thiophenes whose DBE range and carbon number increased with maturity, possibly suggesting an abiotic input of inorganic sulfur. Notably, the maturity indices (MAT) proved suitable for Mesoproterozoic source rocks while exhibiting strong linear relationships.

With the shallow natural gas exploration becoming difficult at present ,deep-seated natural gas exploration has become the hot issue. Tarim basin, which is situated in the western part of China, is the biggest sedimentary basin in China. The study result show that Tarim basin has three major better hydrocarbon source rocks, which are the Cambrian-Ordovician, Carboniferous-lower Permian and Triassic-Tertiary source rocks, and high efficiency gas reservoirs and seal rocks, forming five sets of regional associations of gas reservoir and capping bed. Therefore, the basin has better physical condition for deep-seated gas generation, storage and conservation. Based on the present condition of gas exploration, the authors point out that Kuche depression, Northern uplift, Central uplift, Bachu uplift and South-western depression in Tarim basin has wider exploration prospect for deep seated gas.

Determination and petroleum geochemical significance of short-chain alkylbenzenes in lacustrine source rocks

The Claromecó frontier Basin: Hydrocarbon source rock potential of the Tunas Formation, southwestern Gondwana margin, Argentina

Geothermal resources as a type of renewable clean energy are highly contributive to sustainable development. In this study, the geothermal resources in some sedimentary basins of China were characterized, and sedimentary basins from different eras and of different types were discussed. On this basis, the major influence factors on the geothermal resources of different regions were elaborated. The geothermal resource potentials in major sedimentary basins of China were evaluated. The geothermal resources in the sedimentary basins of China are extensively distributed and diverse, which are geologically different from East to West China. The target strata of faulted basins in East China, superimposed basins in Central China, and cratonic basins in West China are mainly Cenozoic strata, Mesozoic strata, and Paleozoic strata, respectively. These target strata experienced different types of thermal events in geological historical periods. The Cenozoic faulted basins in East China are mostly heat basins. The Cenozoic sediments are superthick and largely differ in thickness among regions. The effects of Cenozoic geothermal events and the major controlling factors both differed among regions, and the causes of differences included thermal subsidence activities and magmatic activities. These basins are major potential zones for exploitation of hot dry rocks in China. The Mesozoic superimposed basins in Central China are mostly temperate basins, and the ground temperatures nowadays are mainly controlled by thermal subsidence. The potential target zones of hot dry rocks in these basins are the Paleozoic strata in the southwest of basins, which can develop into medium-temperature geothermal resources. In the Paleozoic cratonic basins in West China, the Paleozoic marine sedimentary strata are the major target strata of hot dry rocks. The Paleozoic volcanic events little affected the formation of hot dry rocks, and the formation of major hot dry rocks relied on superthick sedimentary strata, where middle- to low-temperature geothermal resources developed.

Formation and distribution of volcanic hydrocarbon reservoirs in sedimentary basins of China

The southwestern area of the Ordos Basin, China, contains good oil/gas systems, similar to the main basin. However, no oil/gas reserves have been found because some magmatic rocks with different occurrences developed in the region, it resulted in the suspension of oil/gas exploration in the 1980s. By means of integrated research based on field investigation, geophysical interpretation, and data of drilling wells, this paper indicates that magmatic activities in the southwestern Ordos Basin display different properties over multiple periods. The Proterozoic and Palaeozoic magmatic rocks are mainly distributed as a large batholith in the Qinling Orogen, and the Qilian Orogen around the southwestern margin of the Ordos Basin. These Proterozoic and Paleozoic plutons have no effect on hydrocarbon source rocks and oil/gas generation in the Ordos Basin. However, the Mesozoic magmatic activities developed within the basin have obvious effects on oil/gas generation. Three kinds of exploration regions were selected within the southwestern Ordos Basin according to the distribution of hydrocarbon source and magmatic rocks as well as the thermal degree: (a) the marginal area of the basin, (b) the region of the Longmen Uplift distributed with concealed magmatic rocks within the basin, and (c) the region within the basin far away from concealed magmatic rocks. Three sets of gas source rocks, that is, the Upper Proterozoic algal dolostone, the Middle Ordovician dark shale, the Upper Paleozoic black mudstone of coal system, and one set of oil source rocks of the Upper Triassic lacustrine black mudstone and oil shale, are exposed in outcrops near the margin of the basin. They all display a low thermal degree with vitrinite reflectance (Ro) below 1.3%, and they do not contribute to oil/gas accumulation because of earlier tectonic uplift. The gas source rocks and oil source rocks, which occur within the basin area of the Longmen Uplift, where the concealed magmatic rocks, display an abnormal thermal degree of over maturation with Ro over 3.4% and underwent dry gas generation because of heating from magmatic activity, and they have gas exploration potential. The source rocks distributed within the basin area away from concealed magmatic rocks display a normal thermal degree and oil/gas generation. The Ro of the Upper Triassic oil source rock is 1.0–1.6%, which is under the thermal maturity stage of liquid oil generation, whereas that of the Upper Paleozoic gas source rocks is 2.0–2.5% under the thermal maturity stage of gas generation. Measured Ro and burial depth of source rocks in the region show a linear relationship, which indicate that source rocks experienced thermal evolution and oil/gas generation under the normal burial thermal condition rather than the magmatic activity. This region has the most potential for both oil and gas exploration.