Search

Evaluating residual hydrocarbons is crucial for assessing shale oil and gas reservoirs, significantly impacting resource evaluation and exploration prospects. Previously regarded as lacking hydrocarbon generation potential, the Ediacaran Dengying Formation (Fm) microbial dolomite in the Sichuan Basin has been re-evaluated for its hydrocarbon generation capabilities. While understanding source rock characteristics is vital for petroleum resource assessment, a comprehensive analysis of the dolomite's source rocks, encompassing hydrocarbon generation and residual features, remains undocumented. In this study, we thoroughly analyze the total organic carbon and vitrinite reflectance and extensively utilize pyrolysis analysis, gas chromatography and isotopic analysis of the organic kerogen from the Ediacaran Dengying Fm dolomite samples. The findings affirm that the Ediacaran Dengying Fm dolomite indeed serves as a source rock with moderate hydrocarbon generation and residue capabilities. This microbial dolomite was formed in a reducing marine environment with high salinity. Characterized by an averaging TOC of 0.82%, the kerogen is primarily identified as type I, with a minor presence of type II, and underwent thermal maturation up to the post-maturity stage. Throughout its geological history, the maximum intensities for hydrocarbon generation and residues were 4.5 × 107 t/km2 and 3.2 × 107 t/km2, respectively. Additionally, cumulatively generated and residual hydrocarbon quantities amounted to 2.7 × 1012 t and 1.67 × 1012 t, respectively. This study indicates significant exploration potential for the Ediacaran Dengying Fm microbial dolomite. Consequently, the central region in the Sichuan Basin has been identified as a promising area for future exploration endeavors. Our study provides valuable insights for the understanding of shale gas exploration in high-maturity source rock areas. [ABSTRACT FROM AUTHOR]

Fossil fuel resources are invaluable to economic growth and social development. Understanding the formation and distribution of fossil fuel resources is critical for the search and exploration of them. Until now, the vertical distribution depth of fossil fuel resources has not been confirmed due to different understandings of their origins and the substantial variation in reservoir depths from basin to basin. Geological and geochemical data of 13 634 source rock samples from 1286 exploration wells in six representative petroliferous basins were examined to identify the maximum burial depth of active source rocks in each basin, which is referred to in this study as the active source rock depth limit (ASDL). Beyond the ASDL, source rocks no longer generate or expel hydrocarbons and become inactive. Therefore, the ASDL also sets the maximum depth for fossil fuel resources. The ASDLs of basins around the world are found to range from 3000 to 16 000 m, while the thermal maturities (Ro) of source rocks at the ASDLs are almost the same, with Ro ≈3.5±0.5 %. The Ro of 3.5 % can be regarded as a general criterion to identify ASDLs. High heat flow and more oil-prone kerogen are associated with shallow ASDLs. In addition, tectonic uplift of source rocks can significantly affect ASDLs; 21.6 billion tons of reserves in six representative basins in China and 52 926 documented oil and gas reservoirs in 1186 basins around the world are all located above ASDLs, demonstrating the universal presence of ASDLs in petroliferous basins and their control on the vertical distribution of fossil fuel resources. The data used in this study are deposited in the repository of the PANGAEA database at: 10.1594/PANGAEA.900865 (Pang et al., 2019). [ABSTRACT FROM AUTHOR]

The north‐eastern Ordos Basin in Central China has become an exploration target in recent years due to the potential of natural gas resources in the Upper Palaeozoic strata. In this study, by analysing the geochemical characteristics of the source rocks and the natural gas, the genesis of the Upper Palaeozoic natural gas was identified. In addition, the accumulation process was discussed by combining studies of hydrocarbon generation and burial/thermal history. The results reveal three sets of source rocks developed in the study area—Carboniferous Benxi (C2b), Permian Taiyuan (P1t), and Shanxi (P1s) formations—consisting of mudstones, carbonaceous mudstones, and coals. The source rocks contain abundant Type III organic matter and have entered mature to high‐mature stage, while source rocks in the south‐eastern part of the study area have entered the overmature stage due to the activity of Zijinshan magmatic rocks. The natural gas has a high content of methane (average 93.99%). The stable carbon isotope of methane (δ13C1) value (average −37.05‰) and that of ethane (δ13C2) value (average −26.4‰) and the composition of the light hydrocarbons reflect the idea that the natural gas is organic in origin, thermogenic, and mainly terrigenous‐sourced. The evolution of a transitional to continental depositional environment of the source rocks results in the variation in the geochemical characteristics of the Upper Palaeozoic gas in the study area. Analysis of fluid inclusions indicates a long and continuous period of natural gas charging in the study area from 165 to 65 Ma. Sandstone bodies close to or interbedded with the source rocks made the gas charging from the source rocks to the reservoirs over a short distance with high efficiency, while faults and fractures provided paths for the gas migrating to reservoirs vertically far from the source rocks. The huge gas generation potential of the source rocks and continuous distribution pattern of sandstone bodies provides favourable conditions for the development of a large‐scale natural gas reservoir. [ABSTRACT FROM AUTHOR]

The genetic type and accumulation model of the Devonian reservoirs in the Marsel Block remain unclear, despite decades of exploration history. According to the well testing, logging interpretations and sample testing results, the Devonian natural gas reservoir in the Marsel Block has five typical characteristics: (1) It is obvious that the traps contain continuous gas accumulations. Not only the apexes of the structures are enriched in natural gas, but also the slopes and depressions contain gas accumulations. (2) The gas reservoirs are classified as tight reservoirs, but there are also reservoirs with high porosity and permeability in some areas. (3) The general negative or low-pressure in the gas reservoir is obvious, although the pressure in the target layers of some wells is close to normal. (4) The yields of single wells in the Devonian reservoir are quite different: some wells have low yields or are dry, whereas the gas production from high-yield wells has reached 700 000 m3/day. (5) The gas-water relationship is complicated: there is no obvious gas-water interface, but the water-producing layer is generally located at the apexes of structures. Research and analysis have shown that using the model of the conventional gas reservoirs genetic type can only explain the characteristics of parts of the gas reservoir, while the model of accumulation in a deep-basin gas reservoir cannot fully explain the distribution characteristics of the Devonian reservoir. However, the model of accumulation in a stacked complex continuous oil and gas reservoir can reasonably explain the geological and distribution characteristics of the Devonian reservoir. Moreover, the predicted gas distribution along a cross-section of the reservoir is also in agreement with the geological background and tectonic environment of the Marsel Block, therefore, the genetic type of the Devonian natural gas reservoir in the Marsel Block is a stacked complex continuous tight-gas reservoir. Finally, by comprehensively analyzing the source rock, reservoir and cap rocks, as well as the structural characteristics, it is verified that Devonian in the Marsel Block has favorable geological conditions for formation of a superimposed continuous tight gas reservoir. [ABSTRACT FROM AUTHOR]

The Lower Permian Taiyuan Formation is a lithic-abundant, tight gas sandstone reservoir in the Kangning field, northeastern Ordos Basin. To clarify the gas accumulation process in tight gas sands, the relationship between the densification of Taiyuan Formation sandstones and gas charging is analyzed. Core porosities of the Taiyuan Formation are mostly below 10%, and air permeabilities are below 1 mD. The sandstone reservoirs are characterized by strong heterogeneity. Dissolution pores and large amounts of micropores in clay minerals dominate the storage space. This porosity is the result of the impact of diagenesis. Porosity evolution modeling confirmed well the prediction of the period of sandstone densification (225-215 Ma) based on the basin analysis as well as diagenetic calibration. Strong compaction dominated the physical property (porosity and permeability) reduction with cementation as a subordinate factor. The integration of burial history and fluid inclusion data suggested that large quantities of gas migrated into the Taiyuan sandstone reservoirs from 176 Ma to 80 Ma when the reservoirs were already tight (porosity <10%). Gas expansion forces provided by source rocks were the main driving force for gas charging instead of buoyancy. Since the late Cretaceous, uplift activity had little influence on Taiyuan tight gas-sands due to self-generation and self-storage. Overlapping sandstone bodies interbedded with high-thickness and good-quality source rocks jointly determined development of tight gas sands. These study results may explain the gas accumulation process and provide insights into gas exploration and development when this method is applied elsewhere. • A new method to indicate the type of gas accumulation. • Three stages of gas accumulation process for Taiyuan Formation in Kangning area. [ABSTRACT FROM AUTHOR]

Decrease in TOC of the carbonate source rock with low total organic carbon (CSRLTOC) contents with hydrocarbon generation and expulsion (a, b, c) and the lower limit of TOC (LLTOC) decreases (d) with the increasing T max or VR. • The CSRLTOC (carbonate source rocks with low total organic carbon) can be effective to oil/gas accumulation in China. • The LLTOC (lower limit of total organic carbon) for effective carbonate source rocks at various mature stages is determined. • Some oil/gas fields have derived partly or mostly from the CSRLTOC. • The CSRLTOC should be conducted for more in-depth studies in the future. Carbonate rocks with high maturity and low total organic carbon content are widely distributed in China. Whether they can be effective source rocks remains controversial, but they have great significance for the evaluation of hydrocarbon generation potential and exploration prospects of carbonate rocks. Dataset reveals that as the depth or maturity increases, total organic carbon (TOC) content, atomic H/C ratio, and hydrocarbon generation potential of carbonate source rocks with low total organic carbon (CSRLTOC) all decrease because of hydrocarbon expulsion. Moreover, some pyrolysis experiments also indicate that the CSRLTOC are able to generate and expel a quantity of hydrocarbons. The above studies indicate that CSRLTOC can be effective source rocks for oil/gas pools. The unique features of carbonate rocks and CSRLTOC demonstrate that they are easier to expel hydrocarbons and contribute to oil/gas reservoirs than shale, and thus, the lower limit of TOC (LLTOC) of effective carbonate source rocks could be smaller than shale (0.5%). The LLTOCs of effective carbonate source rocks with type I-II 1 kerogen (mainly sapropelic group) at the levels of immaturity and low maturity, maturity, high maturity and over maturity are TOC = 0.5%, 0.5–0.3%, 0.3–0.2%, and 0.2–0.1%, respectively. If the carbonate source rocks are at the high-over mature stage, we could take 0.2% as the LLTOC. The present organic-poor source rocks with high maturity are possibly moderate or good source rocks at the low mature level in the geological periods, especially carbonate source rocks if type I-II 1 kerogen. Some typical oil and gas fields in China derive partly or mostly from the CSRLTOC, proving that CSRLTOC could be effective source rock in China. [ABSTRACT FROM AUTHOR]

Reliably and conveniently predicting oil and gas prospects and avoiding costly drilling mistakes are the goals pursued by oil explorers and companies. In 2013, the Anyue gas field was discovered in Sichuan Basin, and it was the first discovery of a giant natural gas field in Precambrian strata attracting extensive attention since then. However, the complexity of geology in the Sinian-Lower Paleozoic makes prediction of oil and gas prospects very challenging. Based on the comprehensive review of the Anyue gas field, we identify four functional elements, i.e., a source kitchen (S), paleo-uplift (U), reservoir depositional facies (D), and regional cap rock (C). The combination of these four functional elements in time and space (T- CDUS) controls the Sinian-Lower Paleozoic hydrocarbon accumulation. The probability for hydrocarbon accumulation is determined by a proposed index, Tcdus. As a tectonic movement can damage oil and gas reservoirs formed prior to the movement, a model for calculating the hydrocarbon reservoir preservation probability is also established. The oil and gas prospects in Sinian-Lower Paleozoic are predicted with the combination of the hydrocarbon accumulation and preservation model. 137 wells drilled in the Sichuan Basin show that 88.9% of the successful wells are distributed in the predicted zones. • Four functional elements control the formation of oil and gas reservoirs. • Damage of tectonic movement to petroleum accumulations is analyzed. • The oil and gas prospects of the Sinian-Lower Paleozoic are predicted. [ABSTRACT FROM AUTHOR]

The recent gas exploration in West China demonstrated that formation conditions of tight‐sandstone gas are distinct from typical ones in North America. One remarkable difference is that complicated tectonic conditions in the foreland basin of West China, especially the Himalayan tectonic movement, resulted in widely developed fractures in tight‐sand reservoirs. Thus, this work employed dual media to characterize tight‐sand reservoir system and explain the impact of dual media on tight‐sand gas reservoir by: (a) describing the feature of fractures and properties of Yinan 2 tight‐sand reservoir; (b) characterizing dual media with mercury intrusion porosimetry, full diameter and conventional core analysis; (c) discussing gas charging and accumulating in dual media based on the difference between dual media and tight‐sand rocks. Observation from cores, FMI images and thin sections suggested that macro‐ and micro‐fractures are widely distributed in Lower Jurassic Ahe Formation (J1a) tight sandstones, with dip angle of 70° to 80°. These fractures are strongly scale‐dependent with length of several centimetres to a few tens of centimetres and apertures of several hundreds to several thousands of microns. J1a tight‐sand reservoir is characterized by poor porosity, with an average value of 7.7%, whereas measured permeability varies from 0.01–100 mD. Intrusion and extrusion curves of dual media and tight‐sand rocks are significantly different from each other, while displacement pressure and medium saturation pressure of dual media are lower than tight‐sand rocks. Importantly, maximum pore throats of dual media are 1.75–32.22 times larger than juxtaposed tight‐sand rocks. The ratio of permeability between dual media and tight sandstone is up to 1,000, whereas the ratio of porosities only ranges from 1 to 1.5. Thus, dual media in tight‐sand reservoir represents high permeability system and matrix pores are primarily storage system. The impact of dual media on tight‐sand gas reservoir involves its position, temporal coupling of gas charging and growth. In terms of fracture growth prior to gas charge, multi‐force can work together as a driving force, and fractures as a flow system and matrix pores as a storage system linked by fractures; buoyancy is the primary driving force in fractures. In terms of gas charge prior to fracture growth, dual media can also exert a positive impact on gas charging when occurring in the inner part of tight‐sand reservoir defined by the critical throat threshold. However, dual media can also destroy the "inverted gas–water" and shrink tight‐sand gas reservoir when occurring at the original critical throat threshold. [ABSTRACT FROM AUTHOR]

Although it has been shown that the potential of tight-sand gas resources is large, the research into the mechanisms of hydrocarbon charging of tight sandstone reservoirs has been relatively sparse. Researchers have found that there is a force balance during hydrocarbon charging, but discriminant models still have not been established. Based on the force balance conditions observed during gas migration from source rocks to tight sandstone reservoirs, a calculation formula was established. A formula for identifying effective source rocks was developed with the gas expulsion intensity as the discrimination parameter. The critical gas expulsion intensity under conditions of various burial depths, temperatures, and pressures can be obtained using the calculation formula. This method was applied in the Jurassic tight sandstone reservoirs of the eastern Kuqa Depression, Tarim Basin, and it was calculated that the critical expulsion intensity range from 6.05 × 108 m3/km2 to 10.07 × 108 m3/km2. The critical gas charging force first increases with depth and later decreases with greater depths. The distribution range of effective gas source rocks and total expelled gas volume can be determined based on this threshold. This method provides new insight into and method for predicting favourable tight-sand gas-bearing regions and estimating their resource potentials. Copyright © 2014 John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Tight-sand gas in the Jurassic and shale gas within the fifth member of Xujiahe Formation (T3×5) in the Western Sichuan Basin (WSD) are currentiy regarded as the most proiific emerging unconventional gas plays in China. This study conducted a conventional evaluation of T3×5 source rocks in the WSD, and investigated their hydrocarbon generation and e×pulsion characteristics, including intensity, efficiency and amount. The results show that, the T3×5 source rocks are thick (generally >200 m), and have a high total organic content (TOC), ranging from 2.5 to 4.5 wt%. It is thus indivative of a great hydrocarbon generation potential when they underwent high thermal evolution (Ro>1.2%) in the area. In addition, an improved method of hydrocarbon generation potentiai is applied, indicating that the source rocks reached a hydrocarbon e×pulsion threshold with vitrinite reflectance (Ro) reaching 1.06%, and that the comprehensive hydrocarbon e×pulsion efficiency is about 60%. The amount of hydrocarbon generation and e×pulsion from T3×5 source rocks is 3.14×10 t and 1.86×10 t, respectiveiy, with a residual amount of 1.28×10 t within them. Continuous-type tight-sand gas is predicted to have developed in the Jurassic in the Chengdu Sag of the WSD because of the good source-reservoir configuration; the Jurassic sandstone reservoirs are tight, and the gas e×pelied from the T3x5 source rocks migrates for very short distances verticaliy and horizontaily. The amount of gas accumulation in the Jurassic reservoirs derived from T3x5 source rocks is up to 9.3×10 t. Geological resources of shale gas are up to 1.05×10 t. Small differences between the amounts calculated by the volumetric method and those obtained by hydrocarbon generation potential method may be due to other gas accumulations present within interbedded sands associated with gas shales. [ABSTRACT FROM AUTHOR]

Abstract: Based on the distribution features of present formation pressure, analysis on logging data, and genetic mechanisms of abnormal pressure, the overpressure evolution was reconstructed using numerical basin simulation and other quantitative analysis methods. The phase differences of pressure increasing mechanisms, enhancement differences among different mechanisms, and the control of geopressure evolution on gas migration and accumulation were discussed. The causes of overpressure in the Xujiahe Formation include under-compaction (from early Late Triassic to the end of the Jurassic), hydrocarbon generation (from end of the Early Jurassic to the Neogene) and tectonic compression (since the Cretaceous). It is suggested that tectonic compression and hydrocarbon generation are the principal factors of the present overpressure in the Xujiahe Formation. Overpressure transmission is the main cause of overpressure in the Jurassic strata which occurred during the intense tectonic activity periods since the Cretaceous. The overpressure is the main force for hydrocarbon migration and overpressure-related microfractures are the major pathways for gas migration. Fault transport and overpressure driving caused the formation of Jurassic secondary gas reservoirs with distant sources. The areas with high pressure coefficient in the Jurassic and high-overpressure zones in the Xujiahe Formation are optimum targets for exploration. [Copyright &y& Elsevier]

The Sinian Dengying Formation is a key target for deep oil and gas exploration in the Sichuan Basin, China. Natural gas was mainly distributed in the Ziyang–Weiyuan area (ZWA) and the Gaoshiti–Moxi area (GMA). At present, the genetic types and sources of natural gas are still unclear and controversial. The chemical composition, stable carbon isotopes, and biomarkers were used to analyze geochemical characteristics, genetic types, and gas–source relations. The results showed that the composition and content of hydrocarbon gas in the ZWA and GMA were similar. Natural gas was a typical dry gas with an average dry coefficient (C 1 /C 1 +) of 0.9991, which reflected higher methane (CH 4) content and lower heavy hydrocarbon gas (C 2 +) content. For nonhydrocarbon gas, CO 2 (0.01%–26.34%), N 2 (0.03%–24.95%), H 2 S (0.10%–3.19%), and He (0.01%–0.37%) were mainly distributed. Compared with the GMA, the ZWA was characterized by higher N 2 content and lower CO 2 content. Although the carbon isotopes had not been reversed, the values of δ13C 2 –δ13C 1 were different between the ZWA and GMA, with the GMA having the higher value. The assemblage relation between the natural gas composition and carbon isotopes indicated that the natural gas type was dominated by oil-cracking gas. Mud-shale in the high maturity stage of thermal evolution greatly influenced on the content of N 2 and He. H 2 S mainly belonged to thermochemical sulfate reduction (TSR), and most of CO 2 was formed by deep carbonate metamorphism and TSR. The gas–source relation showed that natural gas in the ZWA was derived from the Cambrian Qiongzhusi Formation and that the gas in the GMA mainly originated from the Sinian Dengying Formation and the Cambrian Qiongzhusi Formation. The established hydrocarbon generation model indicated that the Sinian Dengying Formation is potentially gas-rich. • The Sinian Dengying Formation natural gas was a typical dry gas, dominated by oil-cracking gas. • Source rocks of the Qiongzhusi Formation and Dengying Formation were the mainly gas source for gas reservoirs. • The resource potential was qualitatively evaluated by the established hydrocarbon generation model. [ABSTRACT FROM AUTHOR]

Due to the large resource potential of tight sandstone gas, the Upper Paleozoic strata of the Linxing area has become an important exploration target in the Ordos Basin. In this study, by analyzing the distribution characteristics of tight sandstone gas (TSG), the relations of source-reservoir assemblages were divided into three types containing interbedded with source rocks (Type I), adjacent to source rocks (Type II) and far from source rocks (Type III). Five factors were identified to control their genesis, migration, and accumulation. Firstly, the gas generation intensity of source rocks is larger than 10 × 108 m3/km2, which indicated that source rocks could provide gas to the reservoirs. The gas generation centers of source rocks control the distribution of TSG reservoirs, while the areas among the hydrocarbon generation centers were the enrichment zones for TSG. Secondly, under the condition of generally tight reservoirs, the sandstone reservoir which has good quality (high porosity, high permeability) provided the favorable accumulation condition for TSG. Thirdly, the study area experienced one stage of gas charging mainly from the late early Jurassic to late early Cretaceous, which was 178 to 100Ma. Continuous gas generation and expulsion led to the sustained accumulation of TSG. Fourthly, with the general development of overpressure in the Upper Paleozoic strata, gas expansion force as the main power drive natural gas to migrate into the reservoirs of type I and type II during the accumulation period. Finally, the development of faults and fractures provided a migration path for natural gas charging in the reservoir of type III vertically. The existence of microcracks can improve the petrophysical properties of tight reservoirs. Under the joint control of these factors, the reservoir of Type I is the most favorable exploration target. • The geological characteristics of tight sandstone gas reservoirs in the Linxing area were described. • The five controlling factors on tight sandstone gas reservoirs were discussed in detail. • The favorable exploration target was determined under the joint control of five factors. [ABSTRACT FROM AUTHOR]

Abstract The Upper Triassic Xujiahe Formation is a key target layer for development of tight sandstone gas reservoirs in the Sichuan Basin. Most of the previous work focused on the main reservoirs such as T 3 x2 and T 3 x4 with lack of research attention on T 3 x5, an equally important source-reservoir unit. Here we examine the organic matter and source rock distribution in the T 3 x5 using rock pyrolysis, asphalt extraction, and gas chromatography. The thickness of T 3 x5 source rocks reduces from west and northwest Sichuan Basin to east and southeast Sichuan Basin. The main sedimentary facies are salt lakes and deltas, of which the organic matter originated from aquatic organisms and a small amount of terrestrial matter. The abundance of total organic carbon (TOC) in T 3 x5 is relatively high, at values of 0.07%–7.2%. According to the vitrinite reflectance (R o), pyrolysis, and gas chromatography measurement results, the T 3 x5 source rocks are at the stage of mature to over-mature, and their hydrocarbon expulsion threshold and hydrocarbon expulsion peak correspond to Ro of 1.05% and 1.23%, respectively. Furthermore, a hydrocarbon generation center and a hydrocarbon expulsion center are formed horizontally, with the maximum hydrocarbon generation intensity of 50 × 108 m3/km2 and the maximum hydrocarbon expulsion intensity of 48 × 108 m3/km2. The natural gas resource is 3.19–5.36 × 1012 m3, indicating great exploration potential. Highlights • Evaluate of T 3 x5 source rocks in detail from 5 aspects: sedimentary environment, thickness and distribution, organic matter abundance, organic matter type and organic matter thermal maturity. • Clarify the hydrocarbon generation and expulsion features of T 3 x5 source rocks. • Predict resource potential of the T 3 x5 in Sichuan Basin. [ABSTRACT FROM AUTHOR]