石油实验地质

2021, 43(6): .

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Basic characteristics and exploration potential of shale gas in Longtan Formation of Upper Permian in eastern Sichuan Basin

ZHAI Changbo, DENG Mo, CAO Qinggu, XIAO Xiong, HE Guisong, CHEN Feiran, QIU Jianhua, LIU Xu, ZHANG Changjiang

2021, 43(6): 921-932. doi: 10.11781/sysydz202106921

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Various types of sedimentary facies were developed during the Longtan period of the Late Permian, Sichuan Basin. To discover the shale gas exploration potential of belts with different sedimentary facies, a systematic analysis of shale gas generation conditions was carried out on the basis of different typical wells. The organic-rich shale developed in the Sichuan Basin during the Late Permian Longtan period was mainly distributed in tidal flat-lagoon and shelf facies. With complex lithological combinations, the tidal flat-lagoon facies shale was distributed in the Ziyang-Yongchuan-Qijiang areas. Mudstone, shale, and argillaceous carbonate rocks were interbedded with varying thickness and coal seams were also developed in all sections. Furthermore, it has the characteristics of "high TOC, clay and gas contents, and high porosity". The main organic matter type is type Ⅲ. The shallow water, mixed shelf facies in the Longtan Formation was mainly distributed in the Guang'an-Changshou-Nanchuan area, with reduced coal seams and increased ash content. Coal seams were barely developed in the second member of the Longtan Formation. Its organic matter type is Ⅱ₂-Ⅱ₁, with stable thickness as well as medium TOC and brittle mineral contents. Gas logging was anomalous. The deep-water shelf facies in the Wujiaping Formation were mainly distributed in Shizhu-Wanxian and Guangyuan-Liangping. Coal seams were only developed at the bottom of the Wujiaping Formation. Moreover, the second member of the Wujiaping Formation is composed of siliceous shale and mudstone, which has the characteristics of "high TOC content, high brittle mineral content, high porosity, high gas content, and high gas saturation". Its organic matter type is Ⅱ₁, with widespread organic pores. It is currently the main strata for the exploration and development of Permian shale gas in the Sichuan Basin.

Hydrocarbon accumulation conditions and main controlling factors of the Middle-Upper Cambrian Xixiangchi Group in the eastern Sichuan Basin

SUN Ziming, SUN Wei, LIN Juanhua, MA Qiang

2021, 43(6): 933-940. doi: 10.11781/sysydz202106933

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The petroleum geological elements and main controlling factors of the Middle-Upper Cambrian Xixiangchi Group in the eastern Sichuan Basin were systematically analyzed on the basis of geological outcrops and drilling data. Results showed that the reservoir lithology of the Xixiangchi Group was mainly micritic and silt-crystal dolomites, and the reservoir space was dominated by dolomite inter-crystalline pores, inter-crystalline dissolved pores and karst caves, etc., at the meantime, the reservoir quality is generally poor. The Xixiangchi Group was vertically composed by two sets of source rocks strata: the underlying Lower Cambrian Qiongzhusi Formation and the overlying Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation. The Silurian shale and the Lower Ordovician argillaceous rocks acted as regional and local cap rocks of the Xixiangchi Group. High-quality reservoirs are the necessary prerequisite for hydrocarbon accumulation in the Xixiangchi Group, and the source-reservoir spatial configuration and its effectiveness are the key factors to hydrocarbon accumulation. Though the Xixiangchi Group could have been charged by natural gas generated from the underlying and the overlying source rocks, it is difficult for the natural gas generated from the underlying source rocks to migrate up to the Xixiangchi Group due to the barrier of the Cambrian gypsum layers. However, the faulted anticlines developed over the Cambrian gypsum layer were favorable for hydrocarbon accumulation because they could change and construct a series of effective source-reservoir spatial configuration between the Wufeng-Longmaxi source rocks and the Xixiangchi reservoirs, and finally formed reservoirs with "young source in old reservoir" in the Xixiangchi Group.

Pore structure, hydrocarbon occurrence and their relationship with shale oil production in Lucaogou Formation of Jimsar Sag, Junggar Basin

WANG Jian, ZHOU Lu, JIN Jun, LIU Jin, CHEN Jun, JIANG Huan, ZHANG Baozhen

2021, 43(6): 941-948. doi: 10.11781/sysydz202106941

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In order to study the relationship between shale oil production and reservoir porosity or the oil content, experimental approaches including FE-SEM, LSCM, nano CT, high pressure mercury injection and nitrogen adsorption combined analysis, NMR analysis and molecular simulation were used to quantitatively analyze the full-scale distribution and occurrence characteristics of shale oil in Permian Lucaogou Formation of the Jimsar Sag, Junggar Basin. There are significant differences in the pore-size distribution of various lithologies in shale oil reservoir of the Jimsar Sag. The dominant lithology are arenaceous dolomite, feldspar lithic siltstone and dolomitic siltstone, and the best one is feldspar lithic fine sand rock, with pores larger than 300 nm accounting for 74.1%, and the main body is intergranular (dissolved) pores and intergranular dissolved pores. Fluid occurs with large heterogeneous in micro-nano scale. Heavy components with fluorescence wavelength between 600 and 800 nm attached to mineral pore surface as thin film in pores with a radius above 300 nm, and filled in pores with a radius below 300 nm. The medium components with fluorescence wavelength between 490 and 600 nm occur in the center of pores above 300 nm. The water content is low, and occurs in the center of the pores above 300 nm wrapped by the medium component. The lower limit of pore throat production of shale oil in the Lucaogou Formation is 50 nm. Above 300 nm, the hydrocarbon in pore throat is easy to be produced and is the main contribution system of current productivity. The recovered crude oil with medium density is mainly from large pore above 300 nm. Pore-throats distributed between 50 to 300 nm are difficult for the shale oil producing, which is the key to enhance oil recovery. Negative pressure and temperature rise can effectively improve the mobility of hydrocarbons in nano-scale pores.

Tectonic evolution characteristics of Lishui Sag, East China Sea Shelf Basin

LIU Huan, XU Changhai, SHEN Wenlong, WANG Danping, DENG Yuling

2021, 43(6): 949-957. doi: 10.11781/sysydz202106949

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To detailly describe the tectonic evolution history of Lishui Sag of the East China Sea Shelf Basin, eight seismic sections from north to south were selected. The balanced section technology was used to restore structural evolution section, and some parameters such as extension amount, ratio and rate were measured. The extension characteristics of the sag during ten geological periods were described quantitatively and finely, moreover, the stage and spatial extension characteristics were also discussed. The structural evolution of the sag were classified into six stages: the initial, early and late stages of fault depression, the depression stage, the inversion stage and the stable subsidence stage. It was considered that the most intense stage for fault depression and fault activity in the sag was the deposition stage of the lower Lingfeng Formation (T₉⁰-T₈⁸), and the extension and contraction characteristics of different evolution stages were different in space. The tectonic evolution of the Lishui Sag, controlled by the geodynamic background of retrogressive subduction of the (paleo) Pacific plate to the Eurasian plate, reflects the rule of tectonic and sedimentary migration from west to east in the East China Sea Shelf Basin since the Late Mesozoic, and is closely related to the interaction of the convergence plates around the East China Sea shelf Basin.

Geological characteristics and distribution of global primary hydrocarbon accumulations of Precambrian-Lower Cambrian

LI Gang, BAI Guoping, GAO Ping, MA Shenghui, CHEN Jun, QIU Haihua

2021, 43(6): 958-966. doi: 10.11781/sysydz202106958

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In recent years, primary hydrocarbon accumulations of Precambrian-Lower Cambrian have caused an increasing attention in the oil and gas explorations worldwide. The Eastern Siberian Basin in Russia, the Oman Basin in the Middle East, and the Sichuan Basin in China are endowed with the richest oil and gas reserves in the Precambrian-Lower Cambrian primary hydrocarbon accumulations. This study takes these three basins as examples to systematical and comprehensively document the geological characteristics and distribution of the global Precambrian-Lower Cambrian primary hydrocarbon accumulations through a large amount of data analysis and statistics, to provide insights for further breakthroughs of oil and gas explorations in ancient stratigraphic successions of sedimentary basins. The global proven and controlled reserves of Precambrian-Lower Cambrian primary hydrocarbon accumulations have reached 30.09×10⁹ boe (4.12×10⁸ t), of which 84.2% are distributed in the Eastern Siberian Basin, while the Oman Basin and the Sichuan Basin account for 8.9% and 6.5%, respectively. The source rocks are dominated by marine mudstones, shales and carbonate rocks, which are generally immature to over-mature and mostly distribute in low structural parts. Carbonate rocks and clastic rocks are important types of reservoir rocks. Early dolomitization, superficial leaching and hydrocarbons injection are important mechanisms for the development of ancient carbonate reservoirs. Most of the hydrocarbons in deep and ultra-deep ancient strata are stored in carbonate rocks. At the same time, the extensively developed high-quality regional caprocks are the key to preserving abundant hydrocarbons. Three types of accumulation models, self-generating and self-preserving, reservoirs adjacent to source rocks, and reservoirs isolated to source rocks, constitute the main models of Precambrian-Lower Cambrian primary hydrocarbon accumulations.

Meander-braided transition features and hydrocarbon accumulation characteristics in Neogene Shawan Formation, Chunguang exploration block, Junggar Basin

YUE Xinxin

2021, 43(6): 967-975. doi: 10.11781/sysydz202106967

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The Chunguang exploration area is one of the important oil-gas bearing blocks on the northwestern margin of Junggar Basin. Considerable number of high-yield wells have been developed in the Neogene Shawan Formation during the earlier exploration stage, and great exploration and development potential in this area were indicated. In order to meet the needs of delicate exploration, a further study of the sedimentary characteristics, sedimentary evolution and reservoir forming models were promising for the further exploration. With the analysis of cores, loggings and amplitude slices, the typical sedimentary microfacies of diara and point bar deposits were identified in the study area. Then it was considered that braided river and meandering river deposits were developed in the study area with the feature of "braided river deposits in the east part of study area and meandering river deposits in the west part". Moreover, the sedimentary evolution process was determined and a new sedimentary model was established. With the flattening of terrain, the continuous rising of base level, the weakening of provenance supply and the changing of climate from humid to heat, the sedimentary system was gradually transformed from braided river deposits to meandering river deposits. By the study of reservoir accumulation and recognition characteristics of different river-type deposits, a new reservoir forming model was built. Combined with the understanding of reservoir formation, the favorable exploration direction was indicated, the exploration field was effectively expanded, and good exploration results were obtained, which provided theoretical support for the increase of reserves and production in the Chunguang exploration area.

Sedimentary characteristics of the upper part of the fourth member of Leikoupo Formation of Middle Triassic in western Sichuan Basin

SONG Xiaobo, LONG Ke, WANG Qiongxian, LIAO Rongfeng, CHEN Yin, XU Guoming, SU Chengpeng

2021, 43(6): 976-985. doi: 10.11781/sysydz202106976

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Based on the data of outcrop, drilling core, logging, rock thin section and carbon and oxygen isotope test, this paper carried out systematic analysis for characteristics and model of sedimentary of the upper part of the fourth member of Leikoupo Formation in western Sichuan Basin, favorable sedimentary facies for the development of reservoir were proposed. Results showed that in the sedimentary period of the upper part of the fourth member of the Middle Triassic Leikoupo Formation, the western Sichuan Basin was in the sedimentary environment of tidal flat within restricted and evaporative platform. The sedimentary microfacies were gypseous-dolomite flat, (algae)-dolomite flat, (algae)-dolomite-lime flat, (algae)-lime-dolomite flat, (algae) intraclast beach, (algae)-lime flat, intraclast beach etc. According to the establishment of the sedimentary model, due to the barrier of beach/island and the influence of arid climate conditions, the seawater supply was limited during the deposition of the upper submember of the fourth member of Leikoupo Formation in the western Sichuan Basin, which formed a high salinity sedimentary environment by strong evaporation and was good for large-scale dolomization. Flat terrain, shallow water, low energy, and the frequent exposure of multiple periods caused atmospheric water leaching and dissolution in the western Sichuan region. Algae were widely developed, which formed diverse carbonatite by algal activities, including algal stromatolite dolomite, algal clot dolomite, algal lamina dolomite and algal arene dolomite. By comprehensive analysis, for most part of the western Sichuan Basin, it was in the intertidal zone (algae)-dolomite flat sedimentary area, which was favorable for the penecontemporaneous exposure to atmospheric water leaching and dissolution, and was a favorable developing zone for porous-type reservoir.

The structural evolution of the middle section of the West Sichuan Depression in the Sichuan Basin controlled the hydrocarbon accumulation in the Middle Triassic Leikoupo Formation

MENG Xianwu, LIU Yong, SHI Guoshan, CHEN Lan, ZHU Lan, CAI Zuohua

2021, 43(6): 986-995. doi: 10.11781/sysydz202106986

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The Middle Triassic Leikoupo Formation of Jinma-Yazihe structure in the middle section of Western Sichuan Depression has submitted over 100 billion cubic meters of proved natural gas reserves. An industrial gas flow has also been obtained in Xinchang and Majing area, and the controlled and predicted reserves have been submitted. However, the relationship between structural evolution process and hydrocarbon accumulation configuration is still unclear. Through the analysis of vitrinite reflectance, scanning electron microscopic observation, analysis of fluid inclusion of peripheral outcrop and drilling samples, and combined with structural interpretation, the following results have been indicated. It is clear that the local structure in the middle section of Western Sichuan Depression was formed in the early Indosinian, and the Early-Middle Jurassic was a critical tectonic evolution period for hydrocarbon accumulation in the Leikoupo Formation. Meanwhile, the faults connected to sources or "contact" fault migration system provided pathways for natural gas migration, which was conducive for hydrocarbon enrichment. The local paleo-structural high points with a good configuration of key accumulation factors such as reservoirs and transport systems and weak structural deformation are the most favorable exploration area.

Diagenetic evolution of key minerals and its controls on reservoir quality of Upper Ordovician Wufeng-Lower Silurian Longmaxi shale of Sichuan Basin

WANG Ruyue, HU Zongquan, BAO Hanyong, WU Jing, DU Wei, WANG Pengwei, PENG Zeyang, LU Ting

2021, 43(6): 996-1005. doi: 10.11781/sysydz202106996

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Based on core, thin section, scanning electron microscopy observations, X-ray diffraction analysis, as well as carbon and oxygen isotopes and energy spectrum analysis of carbonate rocks, the quartz, feldspar, pyrite, carbonate and clay minerals in shale of the Upper Ordovician Wufeng-Lower Silurian Longmaxi formations of Sichuan Basin were effectively characterised and classified, and the influences of their diagenetic evolution sequence on the development of shale reservoir were discussed. The results showed that good material basis and unique diagenetic sequence were the key factors for the formation of high-quality shale reservoirs. (1) Framboidal/euhedral pyrite, bio-quartz and microbial dolomite were mainly formed from the syngenetic stage to the A-substage of early diagenetic stage. They were both destructive and constructive for maintaining the original pores in shale, and the constructive supporting framework of which was critical for the formation of high-quality shale reservoir. The rigid framework formed by these early-formed minerals and terrigenous debris facilitated the maintenance of original pores and the reservoir stimulation of shale gas exploitation. (2) The co-evolution of hydrocarbon generation and diagenesis promoted the development of reservoir spaces. In the A-substage of middle diagenetic stage, the production and consumption of organic acids, the dissolution/alteration of unstable minerals (feldspar and carbonate minerals), clay mineral conversion and oil generation from kerogen were synchronic, which provided favorable space for the charging and retention of liquid hydrocarbons during the oil generation period. From the B-substage of middle diagenetic stage to the late diagenetic stage, the shale gas/organic pore generation and pressure increase of kerogen and retained hydrocarbon cracking promoted the development of organic pores and micro-fractures, which was conducive to the enrichment and high production of shale gas.

Evaluation and influencing factors for brittleness of lacustrine shale reservoir: a case study of Qutang Sub-Sag, Subei Basin

SUN Biao, LIU Xiaoping, SHU Honglin, JIAO Chuangyun, WANG Gaocheng, LIU Mengcai, LUO Yufeng

2021, 43(6): 1006-1014. doi: 10.11781/sysydz2021061006

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In order to accurately evaluate the brittleness of lacustrine shale and explore its influencing factors, the mineral compositions, geochemical characteristics and reservoir spaces of the lacustrine shale samples from the second member of Paleogene Funing Formation in the Qutang Sub-Sag, Hai'an Sag, Subei Basin were analyzed by means of whole-rock diffraction analysis, the measurement of organic carbon content (TOC) and vitrinite reflectance, scanning electron microscope (SEM) and triaxial rock mechanics experiment, combining with well logging, strength parameters, mineral compositions and stress-strain curves. The shale is mainly dolomitic and calcite ones with a high content of brittle minerals. The average TOC value is 1.25%, indicating for a mature stage. The reservoir space is composed of ultra-low pores and fractures. The stress-strain curves show a strong characteristic of brittleness. The brittleness evaluation results of different methods have certain differences. The results based on elastic parameters and mineral components are more reliable than that based on strength parameters although each method has its own limitations. The mineral compositions, organic matter abundance, and the degree of storage space development affect the brittleness of shale in the second member of Funing Formation. With the increasing of dolomite content, organic maturity and fracture development, the brittleness of the reservoir increases. The increase in calcite content, organic matter abundance and porosity will weaken the brittleness of the reservoir.

Petroleum charge history of the slope area of Katake Uplift in Tarim Basin

ZHANG Yumin

2021, 43(6): 1015-1023. doi: 10.11781/sysydz2021061015

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Based on the oil and gas observation and diagenetic sequence identification of multiple sets of strata by using drilling data from well Zhong 1 on the northwestern slope of Katake Uplift and well Shun 1 in the Shuntuoguole Low Uplift of Tarim Basin, fluid inclusion types, abundance, composition and occurrence state of diagenetic minerals were studied in this paper. The comprehensive use of technical methods and data including homogenization temperature and freezing point determination of fluid inclusions, K-Ar isotope dating of authigenic illites in sandstone reservoirs, paleo-geothermometry, burial and tectonic evolution histories revealed the accumulation, adjustment or deformation of multi-facies of hydrocarbons in various formations on the slope of Katake Uplift. Results indicated three stages of hydrocarbon accumulation in the study area. The first stage was 410-370 Ma (the late Caledonian), the second stage was 280-175 Ma (the late Hercynian to Indosinian), and the third stage was 80-23 Ma (the late Yanshanian to middle and late Himalayan). There were three stages of accumulation in the Lower Paleozoic and two stages in the Upper Paleozoic. The charging and accumulation of oil and gas in clastic rocks concentrated in the late Hercynian.

Differential characteristics of fluid occurrence in tight sandstone reservoirs: a case study of Triassic Yanchang Formation in Ordos Basin

ZHANG Yadong, GAO Guanghui, LIU Zhengpeng, LIAO Haiyu, WANG Guanglun, DING Changcan, MA Hongwei, LI Zeliang

2021, 43(6): 1024-1030. doi: 10.11781/sysydz2021061024

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In order to explore the differential characteristics of fluid occurrence in tight sandstone reservoirs, the Chang 6 and Chang 8 reservoirs in the Triassic Yanchang Formation in HQ and HS areas of the Ordos Basin were employed as research objects, the movable and non-movable fluid saturation of reservoir rocks were quantitatively analyzed with features including permeability interval, area and target strata by using nuclear magnetic resonance (NMR) test and high-speed centrifugal experiments. Results showed that the total movable fluid saturation, as well as the main throat intervals of movable fluid were different in reservoirs with different permeability levels. For the high permeability, movable fluid was mainly controlled by larger throat, while for the low permeability, movable fluid was mainly controlled by smaller throat. Movable fluid saturation positively correlated to the throat radius in the smaller throat radius range (< critical throat radius), and negatively correlated to throat radius in the larger throat radius range (>critical throat radius). The higher the permeability, the larger the critical throat radius.

Genetic mechanism of inner reservoirs of Yingshan Formation of Middle-Lower Ordovician in Tahe Oil Field, Tarim Basin

LÜ Yanping, LÜ Jing, XU Xiangdong, DENG Guangxiao, LIU Yongli, LIU Cunge, ZHANG Zhenzhe, HAN Yongqiang

2021, 43(6): 1031-1037. doi: 10.11781/sysydz2021061031

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The fracture-cave reservoirs of weathering crust on the top of Middle-Lower Ordovician in the Tahe Oil Field of Tarim Basin are the major production layer, and large scale reservoirs are also developed underneath the reservoirs. In order to discuss the genetic mechanism of formation of these reservoirs, carbon and oxygen isotope, strontium isotope, rare earth elements and cathodoluminescence were tested in the well A area. The δ¹⁸O and δ¹³C values of calcite in caves and structural fractures are obviously negative than those in limestone background. The mean value of δ¹⁸O_PDB is -14.74‰, showing a trend of constant δ¹⁸O and variable δ¹³C, which are the calcite lines of atmospheric water formed by degassing. The ⁸⁷Sr/⁸⁶Sr ratios of calcites from caves and structures range from 0.709 622 to 0.709 968, which are obviously higher than the background values, and are mainly affected by crustal strontium. There are no positive anomalies in Ce and Eu elements, indicating that there is no hydrothermal fluid involved. The cathodoluminescence of calcites are mainly orange and dark brown, which represents weak oxidation-reduction environment. The results showed that the fracture-cave reservoirs of the Midde-Lower Ordovician Yingshan Formation in the well A area were formed in the deep slow flow zone of atmospheric water during the Early Hercynian, showing the characteristics of pressure bearing, slow flow and not controlled by the karst drainage base level.

Characteristics and formation mechanism of talc in Permian Maokou Formation, southwestern Sichuan Basin: a case study of first member of Maokou Formation in well A1

REN Haixia, LIN Xiaobing, LIU Ye, JING Yonghong, ZHONG Yumei, KANG Baoping, HAN Zhiying

2021, 43(6): 1038-1047. doi: 10.11781/sysydz2021061038

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Different forms of talc have been developed in the first member of Permian Maokou Formation (P₂m¹) in the Sichuan Basin. As a hydrothermal alteration mineral, its formation mechanism and its influence on the P₂m¹ reservoir need to be further explored. The talc of P₂m¹ in the southwestern Sichuan Basin was studied by means of core observation, thin section identification, scanning electron microscope, and the homogenization temperature of fluid inclusions. Based on the detailed description of the color, structure and occurrence state of talc, the formation mechanism of talc was discussed. The talc of P₂m¹ mainly occurs in micrite bioclastic limestone, bioclastic micrite limestone and limestone dolomite, or in micrite limestone as metasomatic bioclastic particles or star points. The genetic mechanism of talc is metasomatism between siliceous hydrothermal fluid and magnesium-rich carbonate rocks under certain conditions, which belongs to hydrothermal metasomatism. There is a positive correlation between the content of talc and the physical properties of reservoir. Large amount of acid gas (CO₂) may be generated during the formation process of talc, which was favorable for the dissolution and pore preservation of P₂m¹ and finally to improve the reservoir capacity. The existence of talc may be indicative for the migration path and distribution of silicon-bearing fluid, and the hydrothermal high energy area is favorable target for further exploration.

Organic geochemical study of FTIR analysis on source rock extracts: a case study of Lower Permian Fengcheng Formation in Junggar Basin, NW China

HE Mufei, ZHANG Jingkun, MI Julei, CHEN Jun, HU Kai, CAO Jian

2021, 43(6): 1048-1053. doi: 10.11781/sysydz2021061048

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To discover the values of Fourier Transform Infrared Spectroscopy (FTIR) in the research of organic geochemistry, hydrocarbon generation features of source rocks of Lower Permian Fengcheng, Junggar Basin were studied by the means of FTIR analysis on the extracts. Seven FTIR functional groups appeared to have indicative significance, based on which three new index were proposed, including A index (A_{2 920}/A_{3 600}), B index (A_{2 920}/A_{1 460}), and C index (A_{1 140}/A_{1 600}). Specifically, A index unraveled a higher hydrocarbon generation potential of the source rocks located in saline areas, B index indicated that the possible hydrothermal fluid injection have caused the abnormal thermal evolution of organic matter in saline source rocks, and C index showed that an increasing salinity from marginal zone to saline zones has affected to the organic molecular polymerization in the Fengcheng Formation source rocks. Based on that, the saline zone located at the center of Fengcheng Formation deposition has great potential for oil-gas exploration, particularly for light oils in the deep reservoirs. These understandings provided new references for the regional oil-gas exploration and pointed out that FTIR can supplement traditional organic geochemistry, displaying a broad application potential.

Geochemical characteristics of solid bitumen in the Jurassic Sangonghe Formation in the central Junggar Basin and its implications for hydrocarbon accumulation process

ZHANG Hui, CHEN Yong, WANG Xuejun, LIN Huixi, WANG Miao, REN Xincheng

2021, 43(6): 1054-1063. doi: 10.11781/sysydz2021061054

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The ubiquitously distributed solid bitumen in the Jurassic Sangonghe Formation reservoir in the central Junggar Basin recorded the important information of hydrocarbon accumulation. In this study, based on lithology, reflectance of bitumen, laser Raman spectroscopy and biomarkers of bitumen, combined with the history of structure evolution and hydrocarbon accumulation, we studied the genesis of the reservoir bitumen and its indication for oil and gas accumulation. Results indicated that these solid bitumen were mainly distributed in structural fractures, the crack surface of the samples have experienced bending deformation, combined with obvious deformation of mineral microstructure. Solid bitumen was then indicated to be derived from the crude oil evolution after the destruction of the ancient reservoir due to tectonic activities. According to the parameter characteristics of biomarkers of bitumen, the crude oil was mainly derived from the source rocks of the Permian Fengcheng Formation and the Lower Wuerhe Formation. Therefore, the Sangonghe Formation reservoir has multi-source charging features. Due to the low maturity (equivalent vitrinite reflectance: 0.62%-0.79%) of bitumen and the evidence for biodegradation, we concluded that the bitumen was generated by biodegradation. Whereas the biomarker showed that the bitumen was affected by the late oil accumulation. In conclusion, the ancient oil reservoirs were formed during the early stage of the formation of Che-Mo ancient uplift in the Middle Jurassic, and were destroyed during the Late Jurassic to the Early Cretaceous. Light hydrocarbon components were dissipated because of the reservoir destruction, then bitumen was formed due to the biodegradation. In the Early Cretaceous, there was no strong tectonic activity in the Sangonghe reservoir after the late hydrocarbon accumulation from the Lower Wuerhe Formation. With the reburial of the reservoir and hydrocarbon accumulation, the hydrocarbon reservoirs today were formed. Although the reservoir of the Sangonghe Formation has undergone tectonic activity adjustment in the study area, the recharge of oil and gas makes it still a favorable exploration target.

Effects of elemental sulfur and sulfur-bearing minerals on the thermal evolution of aromatic compounds in solid bitumen

ZHANG Yanyan, LI Shuifu, HU Shouzhi, FANG Xinyan, WU Liangliang

2021, 43(6): 1064-1077. doi: 10.11781/sysydz2021061064

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Previous studies have shown that some of the aromatic compound parameters have good correlation with the maturity of organic matter. However, it is still unknown whether the widely used aromatic maturity-related parameters are available with the co-existence of sulfur (elemental and/or sulfur-bearing minerals). Artificial simulation experiments of solid bitumen together with elemental sulfur and/or sulfur-bearing minerals (e.g., pyrite, ferrous sulfate, iron sulfate, and calcium sulfate) were carried out to investigate the influence of elemental sulfur and sulfur-bearing minerals on the thermal evolution of aromatic compounds. Results illustrated that some reactions including methylation, alkyl rearrangement and demethylation of aromatic compounds were affected with various extents by the existence of elemental sulfur and sulfur-bearing minerals. Thus, the applicability of the aromatic index should be careful. This study also found some parameters that still can effectively evaluate the maturity of organic matter in the sulfur-bearing environment, such as 1,2,3-TMN/2,3,6-TMN, P/(P+∑MP), MPI and 4,6-DMDBT/3,6-DMDBT.

Guiding and method for division of petroleum exploration play in superimposed reformation basin

FANG Chengming, LIANG Yusheng, YAN Xiangbin

2021, 43(6): 1078-1088. doi: 10.11781/sysydz2021061078

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Reasonable play division played an important role in the evaluation for the exploration and deployment in petroliferous basins. However, there were few studies on the play division in superimposed reformation basins of central and western part of China with multi-cycle evolution and complex accumulation process, and there was no relatively unified scheme. Based on the concept and extension of the play, it was proposed in this paper for the idea, method and process of division with the main line of "prototype-controlled sources and superposition-controlled accumulation" with the view of the characteristics of superimposed reformation basins with multiple sets of combinations, multi-phase reforms, and multiple types of petroleum systems. Play division needs to be started from the overall study of the basin, analysis for the distribution of original reservoir-forming geological elements and the subsequent generation, migration and accumulation of hydrocarbon in the process of basin construction and reformation, clarify the types and distribution of petroleum systems of different plays in the basin during the process of superposition and reformation, reveal the main controlling factors of hydrocarbon accumulation in each type of petroleum systems, and determine the types and boundaries of the plays. According to the type of petroleum system, the play name adopted the combination of "(paleo) and modern tectonic unit + strata or combination + main controlling factors of reservoir". The play division scheme plays a guiding role in deepening the understanding of the regularity of hydrocarbon enrichment in the basin and guiding exploration practice.

Co-occurring characteristics of pore gas and water in shales: a case study of the Lower Silurian Longmaxi Formation in the southeastern Sichuan Basin

YU Lingjie, LIU Keyu, FAN Ming, LIU Youxiang

2021, 43(6): 1089-1096. doi: 10.11781/sysydz2021061089

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Abstract:
In this paper, the co-occurring characteristics of pore gas and water in the Longmaxi Formation shales in the Sichuan Basin, South China were investigated. Water vapor and methane adsorption by the means of gravimetric methods were carried out to quantitatively determine the behavior of gas and bounding water in micro-nano pores. The impact of the shale compositions and pore structures on the occurring characteristics were discussed. Results showed that the storage capacity of bound water in different types of shales varied dramatically, and the characteristics of bound water could be described by the water vapor adsorption curve and the GAB model. There is an apaprent positive correlation between the maximum monolayer water molecule adsorption capacity and the clay mineral content in shales, indicating that clay minerals provide the main active adsorption sites for water molecules. The adsorption capacity of shale to water molecule is higher than that of methane molecule overall, and methane molecule mainly exist in pores with the form of monolayer adsorption. Bound water, adsorbed gas and free gas could be stored in different pore ranges of different shales. Pores with diameters lower than 2 nm are occupied by bounding water and adsorbed gas. For shales with TOC < 2.5%, free gas would be stored in pores with diameters larger than 5 nm approximately, while for the shales with TOC>2.5%, free gas would be stored in pores with diameters larger than 3 nm approximately. The higher the TOC content, the higher the proportion of the free-gas storage space.

Multi-factor evaluation for fine grading of tight sandstone reservoirs: a case study from H3 sand group in the upper section of Oligocene Huagang Formation, Xihu Sag, East China Sea Basin

GAO Mengtian, LU Yongchao, DU Xuebin, MA Yiquan, ZHANG Jingyu, DENG Kong

2021, 43(6): 1097-1106. doi: 10.11781/sysydz2021061097

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Abstract:
The H3 sand group of the upper section of the Oligocene Huagang Formation in the western sub-sag of the Xihu Sag of the East China Sea Continental Shelf Basin is a tight sandstone reservoir with low porosity and low or ultra-low permeability. The distribution of high-quality reservoirs has become a key factor restricting productivity. Based on coring, well logging and physical property test data, the sedimentary microfacies and physical properties of the H3 sand group were studied, and a fine grading evaluation and "sweet spot" prediction were carried out. The reservoir distribution in the H3 sand group was mainly affected by four factors: structural characteristics, sedimentary microfacies, sand thickness and conditions of porosity and permeability. Moreover, on the basis of comprehensive analysis of the relationship among these factors and gas saturation, a four-factor reservoir fine grading evaluation method was proposed. The H3 sand group reservoirs were divided into three types: "sweet spot" reservoirs (type Ⅰ), medium reservoirs (type Ⅱ) and ineffective reservoirs (type Ⅲ).The H3-3 single sand layer has a great exploration potential, followed by the H3-1, H3-2 and H3-4 single sand layers.

2021, 43(6): 1107-1107.

Abstract(202) PDF-CN(25)

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2021, 43(6): 1108-1118.

Abstract(177) PDF-CN(38)

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2021 Vol. 43, No. 6

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