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2024, Volume 46,  Issue 6

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2024, 46(6): 封二-封二.
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Pore development characteristics and main controlling factors of tight oil reservoir in the seventh member of Triassic Yanchang Formation, Xunyi area, Ordos Basin
WANG Liangjun, YUE Xinxin, LI Liansheng, WANG Yanpeng
2024, 46(6): 1135-1144. doi: 10.11781/sysydz2024061135
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The seventh member of the Triassic Yanchang Formation (Chang 7 Member) in the Xunyi area of the Ordos Basin is a typical tight oil reservoir characterized by low porosity, low permeability, and strong heterogeneity. Elucidating the pore development characteristics and primary controlling factors of the reservoir is beneficial for tight oil exploration and development. Through thin-section analysis, physical property tests, scanning electron microscopy(SEM), X-ray diffraction (XRD) analysis, and mercury intrusion porosimetry, this study investigated the petrological characteristics, reservoir space, and diagenetic evolution of the tight oil reservoir, revealing its main controlling factors. The reservoir depth in Chang 7 Member of the Xunyi area of the Ordos Basin ranged from 500 to 1 250 m. The lithology was primarily composed of lithic arkose sandstone, followed by feldspar lithic sandstone, with the interstitial materials mainly consisting of calcite, dolomite, and mud. The sand bodies in the reservoir were thick, with high compositional maturity. Rigid minerals, such as quartz and feldspar, which are highly resistant to weathering, made up a large portion of the framework grains. The quartz content ranged from 30% to 77%, with an average of 44.97%, while the feldspar content ranged from 4% to 52%, with an average of 31.61%. The pore types were mostly intergranular dissolved pores and intragranular dissolved pores, followed by residual intergranular pores and a few microfractures. The average porosity was 7.3%, and the average permeability was 0.4×10-3 μm2. The reservoir is in the middle diagenetic stage A and has completed tight compaction during the Cretaceous. The primary factors contributing to reservoir densification included its poor resistance to compaction, carbonate cementation, illite/smectite mixed layers, and authigenic quartz. The quartz and feldspar content and early oil and gas charging preserved a significant quantity of primary pores. The ongoing dissolution and fragmentation during the middle diagenetic stage were the primary causes for the development of secondary pores.
Pore evolution in tight sandstone and its impact on oil saturation: a case study of Chang 6 to Chang 8 reservoirs in Triassic Yanchang Formation, Ganquan area, Ordos Basin
ZHONG Hongli, CHEN Lihua, ZHANG Fengqi, LIANG Yongqi
2024, 46(6): 1145-1156. doi: 10.11781/sysydz2024061145
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Tight sandstone reservoirs exhibit strong microscopic heterogeneity and significant variations in oil saturation. To investigate the variations in pore and throat size distribution during the diagenesis of tight sandstone reservoirs as well as their impact on oil saturation, the study takes the Chang 6 to Chang 8 tight sandstone reservoirs of the Triassic Yanchang Formation in the Ganquan area of the Ordos Basin as a case study. The influence of diagenesis on porosity was quantitatively calculated using methods such as cast thin sections, scanning electron microscopy (SEM), and high-pressure mercury injection. On the basis of the test results, a pore and throat size distribution model during the main hydrocarbon accumulation period was established, constrained by statistical models of pore and throat parameters. The movable fluid saturation during the main hydrocarbon accumulation period was then calculated using integration methods. The results showed that the Chang 6 to Chang 8 tight sandstone reservoirs experienced strong compaction during the early and middle diagenetic stages, with an average porosity reduction of 81.85% due to compaction. Cementation further reduced porosity by about 11.00% on average. Although dissolution increased pore space, the increase was relatively smaller, with an average value of 4.38%. The average paleoporosity at the beginning (128 Ma) and the end (111 Ma) of the main hydrocarbon accumulation period was 13.82% and 8.68%, respectively. The volume proportion of pore and throat radii greater than the minimum flow throat radius (0.1 μm) was low, and the movable fluid saturation ranged from 35.05% to 93.27%. The low pore and throat radii and movable fluid saturation during the main hydrocarbon accumulation period was one of the reasons for low oil saturation. However, due to the influence of authigenic clay minerals on reservoir rock wettability, the current oil saturation has not decreased sharply. The pore and throat size distribution model during hydrocarbon accumulation provides a feasible method for analyzing the evolution of pore and throat size as well as its relationship with oil saturation in similar reservoirs.
Siliceous and calcareous sources in marine high-quality hydrocarbon source rocks: skeleton-wall-shell of organism and their debris
LU Longfei, TAO Guoliang, WAN Junyu, SHEN Baojian, PAN Anyang, QIN Jianzhong
2024, 46(6): 1157-1165. doi: 10.11781/sysydz2024061157
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Using techniques such as ultra-microscopic organic petrology, the study explores the relationship between bioclasts such as siliceous and calcareous skeleton-wall-shell organism and high-quality hydrocarbon source rocks in terms of their biomolecular composition and stability. Common organisms containing biosilica and siliceous derivatives are mainly radiolarians and other protozoa, sponges, diatoms, chrysophytes, and the siliceous skeleton-wall-shell and debris of some planktonic algae like scales-bearing dinoflagellates. The biogenic calcium preserved in high-quality hydrocarbon source rocks is mainly derived from calcareous skeleton-wall-shell and their debris of animals such as planktonic foraminifera and pteropods and planktonic algae like coccolithophores or acritarchs. These biogenic siliceous and calcareous skeleton-wall-shell debris particles often contain varying amounts of organic matter (pectin or scleroprotein, equivalent to type Ⅲ organic matter), which can generate a certain amount of hydrocarbons at high to over-mature stages and can be preserved in the native pores of biological structures.
Overpressure formation mechanism in deep and ultra-deep layers in middle section of southern margin of Junggar Basin and its relationship with reservoir formation: a case study of Hutan 1 gas reservoir
TIAN Zhixin, LIU Gang, PENG Xukai, FAN Changyu, WANG Gang
2024, 46(6): 1166-1176. doi: 10.11781/sysydz2024061166
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In recent years, breakthroughs have been continuously made in deep and ultra-deep oil and gas exploration in the southern margin of the Junggar Basin. Overpressure is commonly developed in the deep and ultra-deep layers of this area. Clarifying the overpressure formation mechanism and its relationship with oil and gas enrichment is of great significance for guiding oil and gas exploration in these areas. In this study, the pressure distribution characteristics in the deep and ultra-deep layers of the southern margin were analyzed using drill stem test (DST)-measured pressure data. The complex overpressure formation mechanism in Hutan 1 (HT1) gas reservoir was identified through comprehensive analysis of mudstone compaction curves, VES-VP cross-plots, and DEN-VP cross-plots. Based on the acoustic emission experiments and stress field simulations, the relationship between overpressure and oil and gas accumulation in HT1 gas reservoir was analyzed and discussed. The analysis showed that: (1) Except for the first row of thrust belts at the mountain front, extremely strong overpressure with a pressure coefficient greater than 2.0 was widely developed in the deep and ultra-deep layers of the southern margin. Vertically, overpressure was distributed in the thick mudstone of the Tugulu Group and its underlying strata. Horizontally, strong overpressure mainly developed in the second and third rows of structural belts at the mountain front in the middle section of the southern margin and in the Sikeshu Sag in the western section. (2) Comprehensive analysis identified that the overpressure in HT1 gas reservoir was caused by undercompaction and structural compression. Regional rapid deposition of thick mudstone caused undercompaction-associated overpressure, while the strong north-south trending compressive stress exerted by the Tianshan uplift during the late Himalayan Movement onto the southern margin caused structural compression overpressure in the deep and ultra-deep layers. (3) The formation of fluid overpressure in the deep layers promoted the folding deformation of the anticline trap in the Qingshuihe Formation of HT1 gas reservoir, forming an optimal area for oil and gas accumulation. Meanwhile, it changed the fluid dynamic field pattern around the Huxi anticline, increasing the gas potential gradient and enhancing the natural gas migration dynamics, thus providing favorable dynamic conditions for oil and gas enrichment in the Huxi anticline.
Slope—sedimentary source rock-type helium enrichment model: a case study of Shenmu Gas Field, Ordos Basin
DING Zhengang, LIU Chenglin, FAN Liyong, KANG Rui, CHEN Jianfa, WANG Haidong, HONG Sijie, MUHAMMAD Aslam Khan
2024, 46(6): 1177-1186. doi: 10.11781/sysydz2024061177
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The Ordos Basin is rich in helium resources, with high helium and helium-rich natural gas fields discovered in areas such as the Yimeng Uplift and the southern Yishan Slope. The enrichment of helium in these gas fields is often closely related to the development of faults. However, the structural background within the basin is complex. To study the characteristics and controlling factors of helium enrichment under different geological backgrounds within the basin, an analysis of natural gas composition was conducted in the northeastern Yishan Slope of the Ordos Basin. Combining basic geological data of the study area and previous research findings, the helium distribution characteristics and geological influencing factors in the Upper Paleozoic of the Shenmu Gas Field in the Ordos Basin were explored. The results showed that the helium content in the Upper Paleozoic of the Shenmu Gas Field ranged from 0.017% to 0.116%, with an average content of 0.05%, meeting the standard of a helium-containing gas field. The helium content showed a spatial distribution pattern of "low in the west and high in the east", with helium content exceeding 0.1% in some eastern areas. There was a significant positive correlation between helium and nitrogen content, indicating a possible inherent connection between the genesis and dissolution-exsolution mechanisms of helium and nitrogen in natural gas reservoirs. The enrichment of helium in the Shenmu Gas Field was influenced by various geological factors: (1) The widely distributed coal-measure source rocks in the Upper Paleozoic provided ample helium; (2) Crustal uplift and tectonic inversion controlled the migration direction of helium and promoted the exsolution and accumulation of dissolved helium; (3) An appropriate amount of carrier gas aided in helium enrichment. Based on the tectonic conditions of the study area and the geological factors controlling helium accumulation, a new helium enrichment model was proposed, the slope-sedimentary source rock-type helium-rich natural gas enrichment model, providing theoretical support for helium exploration and development.
In-situ stress orientation and main controlling factors of deep shale reservoirs in the second member of Paleogene Funing Formation in Gaoyou Sag, Subei Basin
YAN Zeyu, LIANG Bing, SUN Yaxiong, DUAN Hongliang, QIU Xuming
2024, 46(6): 1187-1197. doi: 10.11781/sysydz2024061187
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The shale oil resources in the second member of the Paleogene Funing Formation in the Gaoyou Sag, Subei Basin exceed 700 million tons. However, the complex geological conditions of both its structure and stress significantly impact the shale oil exploration and development in this area. In particular, the lack of clarity regarding the present-day in-situ stress orientations constrains the deployment of horizontal well groups and the design and optimization of fracturing projects. In this study, the applicability of various methods for interpreting in-situ stress orientations in deep shale reservoirs was investigated based on data from regional focal mechanism solutions, specialized logging, and microseismic monitoring of horizontal well fracturing, as well as the experimental analysis such as velocity anisotropy and paleomagnetic tests. The distribution characteristics of the present-day in-situ stress in the Huazhuang area were identified, and their influencing factors were analyzed. The results indicated that the present-day maximum horizontal principal stress direction in the second member of the Funing Formation mainly ranged from 40° to 55°, with an average azimuth of 45°, indicating a northeastward orientation. In the planar view, the in-situ stress orientation in the study area exhibited minor stress deviations on a larger regional scale, mainly influenced by the structural patterns. Furthermore, stress perturbation zones were found near faults, where stress deviations were more pronounced, and the width of these perturbation zones was positively correlated with fault displacement and extension length. Comparative analysis suggested a decreasing applicability of microseismic monitoring, induced fractures/wellbore collapses, core measurements, and array acoustic anisotropy. Specifically, the velocity anisotropy in array acoustic logging was significantly influenced by lithological phase transitions on a planar scale. Based on the interpretation of stress orientations and the dominant trends of natural fractures, the recommended horizontal well deployment azimuth for this area is SE155° to SSE170°.
Prediction and zoning evaluation of in-situ stress field in deep tight sandstone reservoirs of Western Sichuan Depression, Sichuan Basin: a case study of the second member of Xujiahe Formation in Xinchang and Fenggu area
HUANG Tao, LI Ruixue, DENG Hucheng, HE Jianhua, LI Kesai, LIU Yan, XIANG Zehou, DU Yifei, YE Tairan
2024, 46(6): 1198-1214. doi: 10.11781/sysydz2024061198
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The second member of the Triassic Xujiahe Formation (Xu 2 Member) in the Xinchang structural belt of the Western Sichuan Depression in the Sichuan Basin contains tight gas reservoirs with enormous resource potential. However, the geological structure is complex, presenting significant challenges for exploration and development. In particular, the current understanding of its in-situ stress state and distribution patterns is insufficient, severely restricting the selection of sweet spots for engineering, wellbore trajectory optimization, and reservoir fracturing modification. To clarify the current in-situ stress distribution characteristics in the tight gas reservoirs of the Xu 2 Member, the paper analyzed data from core tests, field tests, and well logging interpretation to determine the stress characteristics at individual wells. Considering the disturbances to the stress field caused by tectonic deformation and faults, Rhinoceros and FLAC3D software were used to precisely model and predict the three-dimensional in-situ stress field of the Xu 2 Member. Based on the stress distribution predictions, the minimum principal stress and stress differential, which significantly impacted fracturing and production, were selected as evaluation indicators. The stress field characteristics were zoned and evaluated, and preliminary suggestions were provided for well location deployment, well trajectory, and fracturing modification design in different in-situ stress zones. The results show that the current maximum horizontal principal stress direction in the Xu 2 Member of the Xinchang structural belt mostly ranges from N85° to 108°E, with an overall counterclockwise rotation as burial depth increases. The current in-situ stress regime corresponds to a strike-slip stress mechanism, with the central Hexingchang area showing significantly higher triaxial stress than the Xinchang and Fenggu areas. Moreover, local in-situ stress fields are disturbed by tectonic deformation and faults. The stress zoning results show that the low stress differential and low in-situ stress zones, which are favorable for fracturing modification, mainly develop near the third-order east-west-trending faults and the fourth-order north-south and northeast-trending faults in the Xinchang and Hexingchang areas, as well as in the extensional disturbance areas in the Fenggu area.
Occurrence characteristics of shale oil in the second submember of Da'anzhai Member of Jurassic Ziliujing Formation, central Sichuan Basin
ZHANG Chenyu, LIU Ziyi, WANG Bin, SHAN Shuaiqiang, LU Jianlin, WANG Baohua, ZUO Zongxin
2024, 46(6): 1215-1225. doi: 10.11781/sysydz2024061215
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Although China has abundant lacustrine shale oil resources, their exploitation is challenging. Investigating the various occurrence states of shale oil in shale reservoirs provides value for the exploration and development of shale oil resources. With the shale in the second submember of Da'anzhai Member of Jurassic Ziliujing Formation of the central Sichuan Basin (the Da2 submember) as the research object, the study reveals the occurrence modes of shale oil under different states in various medium pores, through the implementation of the multi-temperature pyrolysis experiment, the observation of pore development characteristics under the scanning electron microscope and the analysis of the pore size distribution before and after oil washing. In the Da2 submember, the shale oil is mainly in the free state (0.42 to 10.88 mg/g), followed by the adsorption state (0.30 to 1.95 mg/g), as revealed by thermal simulation recovery. The reservoir space of shale includes organic pores (pore size: 2 to 600 nm), pyrite intergranular pores (pore size: 10 to 700 nm), shell pores (pore size: 20 to 1 000 nm), quartz/feldspar intergranular pores (pore size: 4 to 500 nm) and clay mineral intergranular pores (pore size: 4 to 500 nm). After oil washing, the results of nitrogen adsorption and high pressure mercury injection demonstrated a significant increase in pores with sizes of 2 to 30 nm and 60 to 1 000 nm, where most of shale oil is stored. Meanwhile, it was demonstrated that the shale oil in the Da2 submember mainly occurs in organic matter and pyrite by establishing a heat map of the relationship between the occurrence state of shale oil and the medium in the rock. Lastly, by fitting the content of shale oil in different occurrence states with the oil volume obtained before and after oil washing, the pore size range for shale oil accumulation in the study area was determined. The free state of shale oil in the Da2 submember primarily accumulates in pores of organic matter and pyrite with pore size of 60 to 700 nm, and the adsorbed state of shale oil mainly accumulates in the organic matter pores with pore size of 2 to 6 nm. In conclusion, this study presents a thorough examination of the occurrence characteristics of shale oil in Da2 submember, and it will support shale oil exploitation efforts in the area.
Genesis of carbonate minerals in shale of Qingshankou Formation, Sanzhao Sag, Songliao Basin
WU Xia, CHEN Ruiqian, BAI Xin
2024, 46(6): 1226-1239. doi: 10.11781/sysydz2024061226
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To reveal the significance of carbonate minerals in continental shale for shale oil and gas exploration and development, this paper takes the carbonate mineral developed shale from the Qingshankou Formation in the Sanzhao Sag of the Songliao Basin as the research object. Through thin-section observation, X-ray diffraction (XRD), carbon and oxygen isotope analysis, and major and trace element analysis, the types and development characteristics of carbonate minerals were analyzed in depth. The material sources and genetic mechanisms for carbonate mineral formation were discussed, and how carbonate mineral development affected shale oil and gas enrichment was explained in detail. The study revealed that the shale from the Qingshankou Formation in the Sanzhao Sag developed three types of calcite (biogenic shell carbonates, micritic calcite, and sparry calcite) and two types of dolomite (micritic and fine-grained dolomite). Through the analysis of stable carbon and oxygen isotopes, and major and trace elements, it was shown that the carbonates in the study area mainly formed in a stratified, anoxic, reducing, and moderately to highly productive environment within a closed saline lake. The genesis of different types of carbonate minerals varied. Biogenic shell carbonates, micritic calcite, and micritic dolomite were mainly controlled by biochemical action, and the sparry calcite and fine-grained dolomite were formed through recrystallization. Results from rock organic carbon content and rock pyrolysis tests indicated a positive correlation between carbonate content and total organic carbon (TOC) content and a positive correlation between TOC content and hydrocarban generation potential(S1+S2)values, indicating that the carbonate mineral developed intervals in continental shale were high-quality shale development zones. Additionally, the formation of intercrystalline and dissolution pores associated with carbonate minerals created storage conditions for the accumulation of oil and gas in the shale.
Favorable lithologic combinations for shale oil enrichment in the second submember of Da'anzhai Member, Jurassic, central Sichuan Basin
LIU Ziyi, CHEN Dongxia, LEI Wenzhi, ZHU Chuanzhen, LU Longfei, ZHU Jianhui, ZHANG Chenyu
2024, 46(6): 1240-1252. doi: 10.11781/sysydz2024061240
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The lithologic combinations in lacustrine shale strata in China are complex, and shale oil content varies significantly across different combinations. Identifying favorable lithologic combinations will assist in locating shale oil-rich zones. This study takes the shale strata of the second submember of the Da'anzhai Member (Da 2 submember) in Jurassic of the central Sichuan Basin as a case study. Using mineral composition analysis and core observation, four primary lithologies were identified: shell limestone, shale with interbedded shell layers, shell-bearing shale, and pure shale. Various types of pores and fractures develop in each lithology, with bedding-parallel microfractures being more developed in shell-bearing shale and pure shale. To further reveal the pore and fracture system in the shale strata, the proportion of oil-wet and water-wet pores and fractures in the rock (pore and fracture configuration) were determined through one-dimensional nuclear magnetic resonance (NMR) experiments. The pore and fracture configuration values of shell limestone and shale with interbedded shell layers exceeded 60%, indicating restricted oil and gas migration. Due to the development of bedding-parallel microfractures, the pore and fracture configuration values in shell-bearing shale and pure shale were less than 60%, indicating that these lithologies provided more favorable migration channels for oil and gas. Furthermore, influenced by the hydrocarbon supply capacity and the resistance in oil and gas migration, rocks with total organic carbon (TOC) content greater than 1.0% as well as pore and fracture configuration values greater than 60% possessed more residual oil and exhibited better mobility than those with pore and fracture configuration values smaller than 60% (S1ranging from 0.86 to 2.19 mg/g, with an average of 1.42 mg/g; OSI values ranging from 65.96 to 123.21 mg/g, with an average of 91.98 mg/g). Finally, based on the characteristics of organic matter enrichment, the favorable lithologic combinations for shale oil enrichment in the Da 2 submember in the study area were clarified.
Sedimentary characteristics of post-uplift basins in foreland basin system: a case study of Jurassic Sangonghe Formation in hinterland of Junggar Basin
LI Xiang, DING Yajie, LI Junfei, XU Gang, JING Yadong
2024, 46(6): 1253-1264. doi: 10.11781/sysydz2024061253
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Foreland basins are rich in oil and gas resources, with most being concentrated in the foredeep zone. However, as breakthroughs in oil and gas exploration in post-uplift basins have been made, these types of basins gradually become a research hotspot. The hinterland of the Junggar Basin is a post-uplift basin, and the Jurassic Sangonghe Formation is an important oil and gas-bearing layer in this area. However, there is still a significant debate about the types of sedimentary facies in this formation. With the progress of exploration and the continuous enrichment of geological data, the types and evolution of the sedimentary facies in the Sangonghe Formation have gradually become clearer. To clarify the sedimentary facies types, distribution, and the differences from the foredeep zone in the post-uplift basins of the foreland basin system, the study analyzed geological profiles, cores, well logging, seismic data, and analytical test results. It provided a detailed analysis of the sedimentary facies types, distribution characteristics, and controlling factors of the Sangonghe Formation. The sedimentary facies types of the Sangonghe Formation include braided river delta facies, sublacustrine fan facies, and lacustrine facies. The braided river delta facies are further subdivided into the plain and front subfacies, which are mainly distributed in the Shixi and Mobei areas. The sublacustrine fan facies are mainly distributed in the west sag of well 1 in the basin, characterized by Bouma sequences, with "A" and "B" segments being mostly common. The sediment source for these fans came from the braided river delta in the eastern part of the study area. During the sedimentary period of the Sangonghe Formation, there were three sources in the study area, instead of only two sources from the northwest and northeast as previously believed. Stable heavy mineral analysis showed that the W36 sublacustrine fan was affected by the northeastern sediment source, while the W46 sublacustrine fan was affected by the southeastern source. Sediments in the foredeep zone of the foreland basin were coarse, with simple sedimentary facies types and structural oil and gas reservoirs as the primary trap types. However, sediments in the post-uplift basin had finer grain sizes, with more varied sedimentary facies types, and were dominated by tectonic-lithologic and lithologic oil and gas reservoirs.
Combined control mechanism of weathering and tectonics for basement granite of Qiongdongnan Basin, South China Sea
WANG Junqiang, CHEN Anqing, HU Lin, HOU Mingcai, YOU Li, HE Xiaohu, CAO Haiyang, QUE Youyuan, XIONG Fuhao, WANG Wenbo
2024, 46(6): 1265-1274. doi: 10.11781/sysydz2024061265
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Reservoirs within buried hills in petroliferous basins represent a unique area of exploration. Recent discoveries in the Mesozoic granite buried hills of the Qiongdongnan Basin in the South China Sea show promising exploration prospects. Among these, the Songnan buried hill group in the basin's central part has rich drilling data, with several wells encountering basal granite reservoirs. Fracturing is crucial for reservoir formation in dense crystalline bedrock, but limited research on fracture characteristics and tectonic stress hampers basement buried hill reservoir exploration. This study examines multi-stage fracture development in the Songnan low uplift buried hill based on core observations, thin-section analysis, well logging, and seismic data from five wells. It analyzes cutting relationships, openness, morphology, orientation, and explores tectonic stresses forming two groups of fractures. Tectonic fractures and dissolution holes along them are the main reservoir spaces within the granite basement. They are categorized into northeast (NE) and northwest (NW) trending families. NE trending fractures result from the Paleo-Tethys Ocean closure during the Indosinian period, influencing NW trending fractures. Tectonic extrusion related to western Pacific Ocean subduction during the Yanshanian period contributes to both NE and NW trending fractures. High-density fractures in granite allow atmospheric and underwater seepage and dissolution, forming a three-layer weathered crust reservoir structure: sandstone conglomerate belts, weathering fracture zones, and inner fracture zones. The extensional detachment background during early Cenozoic rift basin formation activates pre-existing fracture systems, enhancing reservoir space through fracture relaxation.
Causes and geochemical significance of total organic carbon anomaly in solid residue samples from source rock pyrolysis simulation experiments in a closed system
CANG Hui, CHEN Zhijun, YANG Dong, CHEN Yiguo, HAN Changchun, LI Ziliang, CHEN Lingling
2024, 46(6): 1275-1285. doi: 10.11781/sysydz2024061275
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Under natural evolution, the total organic carbon (TOC) content of source rocks typically decreases as maturity increases. However, in later stages of pyrolysis simulation experiments conducted in a closed system, the TOC content of solid residue samples would anomalously increase instead of decreasing. By analyzing data from pyrolysis simulation experiments on lacustrine source rock samples from the Mesozoic Yingen-Ejinaqi Basin, the causes of this TOC content anomaly were investigated, and its geochemical significance was explored. The results suggested that this anomaly was related to secondary cracking of crude oil. In the closed system of the experiments, early-formed crude oil was trapped in the reactor, unable to be discharged. As the temperature increased, large-scale oil cracking occurred, converting it into gaseous hydrocarbons and generating pyrobitumen. The insoluble pyrobitumen adhered to the solid residue samples, resulting in an increase of TOC content. Based on TOC variation curve of solid residue samples from the pyrolysis simulation experiments, a new method was established to determine the main gas generation threshold for oil cracking in different types of source rocks. The significant amount of pyrobitumen generated, accompanied by an increase in TOC content, indicated the onset of large-scale oil cracking and gas generation. This method overcomes the shortcomings of existing methods, such as inevitable human errors in determining the main gas generation threshold and the inability to conduct more in-depth study on mixed-source oils.
Genesis and source of Permian natural gas in well Qiatan-1 of piedmont depression, southwestern Tarim Basin
HUANG Li, ZHAO Ying, LÜ Huixian, XIE Xiaomin, LI Li, XIAO Qilin, WANG Zhanghu, CHEN Guo, MENG Qiang
2024, 46(6): 1286-1297. doi: 10.11781/sysydz2024061286
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Recently, a significant breakthrough in natural gas exploration was achieved in well Qiatan-1 in the Permian carbonate strata of the Western Tianshan thrust belt in the piedmont depression of southwestern Tarim Basin, marking the discovery of a new exploration layer in the area. However, this region is characterized by multiple sets of source rocks and extremely complex sedimentary and structural features. Research on the genesis and source of the natural gas in well Qiatan-1 is insufficient, restricting its further natural gas exploration. Therefore, the study systematically investigated the genesis and source of the natural gas in well Qiatan-1 based on regional geological background, geochemical characteristics of the gas, and potential source rock features. The measured results showed that the natural gas in well Qiatan-1 was mainly composed of methane (83.53%), with a gas dryness coefficient (C1/C1-5) of 0.992, and contained relatively high levels of N2 (8.36%), CO2 (7.28%), and He (0.110%). The carbon isotope values of methane, ethane, propane, and CO2 in the gas were -27.8‰, -20.2‰, -18.4‰, and 1.7‰, respectively. Based on the natural gas composition and alkane carbon/hydrogen isotope composition, the natural gas in well Qiatan-1 was determined to be coal-type gas in the high to over-mature stage. Considering the distribution, organic matter abundance, type, thermal maturity of its potential source rocks, the gas in this well was mainly sourced from Permian source rocks in the Permian Qipan Formation, and may also be mixed with a small amount of carbon isotopes, forming heavier inorganic hydrocarbon gases. In addition, the components and isotopic evidence of non-hydrocarbon gases such as N2, CO2, and He showed that a certain proportion of inorganic gas had mixed into the natural gas in well Qiatan-1. The helium isotopic composition suggested that the proportion of mantle-derived helium was about 14.6%, and the He content had reached the standard for helium-rich natural gas (He ≥ 0.100%).
Characteristics of Chang 7 shale gas reservoirs in Triassic Yanchang Formation of Ordos Basin and its exploration and development prospects
WU Kai, GAO Juanqin, XIE Guwei, YANG Weiwei, LUO Lirong, LI Shanpeng
2024, 46(6): 1298-1311. doi: 10.11781/sysydz2024061298
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Abstract:
As the second-largest sedimentary basin in China, the Ordos Basin has enormous potential for oil and gas exploration. The Chang 7 member of the Triassic Yanchang Formation in the basin is extensively distributed with organic-rich source rocks, covering an area of 40 000 to 50 000 km2. These source rocks are characterized by high organic content, with organic matter types mainly being type Ⅰ to Ⅱ1. The Ro values mostly range from 0.9% to 1.2%, indicating that they are in thermal maturity stage. The high content of retained hydrocarbons provides a strong material basis for the development of large-scale shale oil and gas reservoirs. Although the organic-rich mud shale layers in the Chang 73 sub-member have good gas-bearing properties, a systematic analysis of their gas-bearing characteristics is lacking. Using the southern part of the basin's western margin as a case study, multiple analytical methods such as rock geochemistry, organic geochemistry, and isotope analysis were used to identify the geological and geochemical characteristics of the source rock reservoirs in the Chang 7 member. The gas-bearing characteristics and shale gas occurrence states of the Chang 7 member were analyzed, and the shale gas resource potential was preliminarily calculated. The results indicated that the black shale of the Chang 73 sub-member in the study area exhibited good gas-bearing properties, with dissolved shale oil gas being the main component, along with minor amounts of adsorbed gas of kerogen clay minerals and free gas. The average volume of desorption gas was calculated to be 1.91 m3/t. The Chang 73 sub-member contained both shale oil and gas resources, with approximately equivalent quantities. It is recommended to consider both oil and gas development in future exploration and development research. In the central part of the lake basin, where thick black shale of the Chang 7 member occurred, gas content reached 2 m3/t. These reservoirs contained rigid minerals, micropores, and fractures, with high gas abundance and substantial resource potential, making this a favorable area for shale gas exploration. The total shale gas resource of the Chang 7 member was preliminarily estimated to be about 4.25×1012 m3, indicating promising exploration prospects. The favorable exploration areas were identified in the Jiyuan, Gucheng and Zhengning area.
Geochemical characteristics of Jurassic lacustrine source rocks in Kekeya area, Tarim Basin: implications for paleoenvironments and organic matter enrichment
SUN Di, XIE Xiaomin, QU Yang, XIAO Qilin, LI Li, CHEN Cai, WANG Zhanghu
2024, 46(6): 1312-1322. doi: 10.11781/sysydz2024061312
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Abstract:
To further reveal the development characteristics of Jurassic source rocks in the southwest depression of the Tarim Basin and their paleoenvironments, with the aim of guiding future shale oil exploration and development, the study integrated rock pyrolysis, maceral analysis, inorganic geochemistry, biomarker compounds, and carbon isotope analyzes.It explored the development characteristics and organic matter enrichment patterns of coal-bearing mudstones from the Lower Jurassic Kangsu Formation and mudstones and silty mudstones from the Middle Jurassic Yangye Formation in the Kekeya area of the southwest depression, Tarim Basin. The results showed that the total organic carbon (TOC) content in the source rocks of the Kangsu and Yangye formations was relatively higher, ranging from 1.7% to 63.5% (with an average of 24.4%), and 0.6% to 6.9% (with an average of 2.1%), respectively, indicating source rocks of good to excellent quality. Source rocks from both formations exhibited low maturity, being in the low-maturity to mature stage.In addition, carbon isotope analysis of kerogen, thin section observations, and biomarker compound analysis indicated that the parent material of the organic matter in the coal-bearing mudstones of the Kangsu Formation and the lower section of the Yangye Formation mainly derived from higher terrestrial plants, while the silty mudstones of the upper section of the Yangye Formation contained abundant planktonic algae. During the depositional period of the Kangsu Formation, the paleoclimate was warm and humid, and the water environment was freshwater, with suboxic and slightly oxidizing conditions. In the early depositional stages of the Yangye Formation, the paleoclimate was also hot and humid, and the depositional environment was similar to that of the Kangsu Formation, characterized by freshwater and suboxic conditions. With the gradual rise in lake level in the late depositional period of the Yangye Formation, the paleoenvironment transitioned to a brackish and suboxic environment. The hot and humid climate, coupled with increased salinity, was conducive to the reproduction of planktonic algae and other aquatic organisms, thereby affecting the organic matter supply in silty mudstones of the upper section of the Yangye Formation. Furthermore, the enhancement of water reducibility during this period was also beneficial for the preservation of organic matter. In summary, paleoclimate, paleosalinity, and depositional environment are important factors influencing the organic matter enrichment in the Jurassic lacustrine source rocks of the Kekeya area.
A physics and data dual-driven method for real-time fracturing pressure prediction
HU Xiaodong, LIU Junyi, WANG Tianyu, ZHOU Fujian, LU Xutao, YI Pukang, CHEN Chao
2024, 46(6): 1323-1335. doi: 10.11781/sysydz2024061323
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Abstract:
Wellhead pressure prediction is challenging due to problems such as drastic pressure fluctuations, numerous disturbing factors, and complex influencing mechanisms. Current research often adopts traditional physical models which find it difficult to capture multiple nonlinear changes and sudden fluctuations due to the oversimplification of complex formation conditions, fracture characteristics, and fluid dynamics processes, limiting their prediction accuracy and real-time responsiveness in actual operations. Artificial intelligence (AI) models, despite their strong nonlinear fitting capabilities, often lack an in-depth understanding of the physical mechanisms underlying pressure fluctuations and are less sensitive to formation and operational parameters, resulting in poor stability and insufficient interpretability under extreme or dynamically changing conditions. To address these challenges, a physics and data dual-driven prediction method was proposed to predict future pressure trends. An intelligent model based on a long and short-term memory (LSTM) neural network was constructed, integrating the equilibrium height calculations of the proppant bed within the fracture and real-time pumping data at the wellsite as model inputs to predict pressure for the next 60 seconds. Then, combined with traditional wellhead pressure inversion method, wavelet transform was used to decompose predictions from both the intelligent and traditional models. The overall trend of the LSTM model and the characteristics of mutation point in the inverse pressure calculation (IPC) model were utilized to reconstruct the wellhead pressure prediction curves that could balance the overall trend and local fluctuations. Results showed that compared to pure LSTM model, the wavelet fusion model of IPC and LSTM reduced the root mean square error (RMSE) and mean absolute error (MAE) by 37.87% and 15.29%, respectively, in wellhead pressure prediction for the next 60 seconds. The fusion model can accurately capture fracturing pressure changes during field operations, providing more reliable guidance and decision support for field operations.
Microscopic pore and fracture evolution characteristics and influencing factors during imbibition process of shale reservoirs: a case study of the first section of the first member of Longmaxi Formation, western Chongqing area, Sichuan Basin
QIAN Ji'an, JIANG Yuqiang, LUO Tongtong, YANG Yixiao, FU Yonghong, CHEN Weiming, SUN Chaoya, WANG Zhanlei
2024, 46(6): 1336-1348. doi: 10.11781/sysydz2024061336
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Abstract:
Hydraulic fracturing has become an important means for shale gas exploration. Understanding the evolution characteristics and influencing factors of pores and micro-fractures during the imbibition process in shale reservoirs is crucial for optimizing post-fracturing production enhancement measures. This study focuses on the black shale at the base of the first section of the first member of the Longmaxi Formation (Long 1-1 sub-member), the main production layer in the Dazu area, western Chongqing area of the Sichuan Basin. Argon ion polishing and field-emission scanning electron microscopy (FE-SEM) experiments were conducted at fixed sites to observe the evolution pattern of microscopic pores and fractures in shale reservoirs at various stages of water imbibition process. The findings revealed: (1) After water imbibition for 7 days, organic pores at the edges of organic matter exhibited varying degrees of reduction, while the internal pore shapes and sizes remained largely unchanged. (2) Intragranular dissolution pores and intergranular pores exhibited noticeable dissolution effects, resulting in mineral particle dissolution and detachment, which increased the leakage area for shale gas. (3) The water imbibition did not induce a significant amount of new micro-fractures. Instead, it extended existing micro-fractures, with the fracture width expanding by 5 to 10 times after imbibition for 14 days. (4) The surface porosity of the shale reservoir reached its peak value at day 7 of water imbibition. After 7 days, due to the continuous swelling of clay minerals, micro-fracture widths experienced varying degrees of reduction. (5) The intensity of pore and fracture expansion in shale reservoirs was primarily affected by mineral composition and pore permeability properties. Higher contents of unstable minerals and brittle minerals with larger particle sizes led to more pronounced pore expansion effects, which were conducive to post-fracturing shale gas seepage.
Comprehensive evaluation of geological and engineering factors affecting fracturing effectiveness in tight sandstone reservoirs
SU Hang, LI Ruixue, DENG Hucheng, QIN Yuanwei, FU Meiyan, HE Jianhua, ZENG Qinggao, SONG Linke, ZHANG Jiawei
2024, 46(6): 1349-1361. doi: 10.11781/sysydz2024061349
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Abstract:
China's tight sandstone reservoirs possess immense hydrocarbon reserves with substantial development potential. Hydraulic fracturing in horizontal wells is a crucial enhancement method for developing these reservoirs. In tight sandstone reservoirs of the Jurassic Shaximiao Formation of the J gas field in the transitional zone between central and western Sichuan, differences in rock mechanical properties and geomechanical characteristics result in significant variations in fracturing effectiveness across wells despite similar fracturing processes. To enhance the effectiveness and specificity of fracturing, this study examined the impact of three geological factors—brittleness index, minimum horizontal principal stress, and differences between two horizontal principal stresses—on fracturing effectiveness. Based on the difference in horizontal principal stress, the geological conditions in the study area were classified into two categories, type Ⅰ and type Ⅱ, from favorable to less favorable. The influence of various engineering factors on fracturing effectiveness under these two types of geological conditions was analyzed, and optimal ranges for engineering parameters under these conditions were proposed. The Analytic Hierarchy Process (AHP) and Grey Relational Analysis (GRA) were employed to calculate the influence weight of each geological and engineering parameter on fracturing effectiveness, and then a quantitative evaluation model was established. Based on the correlation with fracturing effectiveness, the AHP-based model was selected as the optimal method to evaluate the fracturing effectiveness in the study area. It was also used to verify the rationality of the proposed ranges for engineering parameters outlined in the study and the applicability of the comprehensive evaluation model for fracturing effectiveness. This paper revealed significant differences in the suggested parameter ranges for horizontal well fracturing engineering under different geological conditions, with notably broader ranges for wells in more favorable conditions than those in less favorable ones. The AHP-based model was identified as the optimal geological and engineering comprehensive evaluation model for assessing the fracturing effectiveness in the study area.
Intelligent identification of Cenozoic spore and pollen fossils in Bohai Sea area
SHUI Leilei, QIU Kunqi, WAN Huan, GONG Shengli, LU Wenkai, WEI Wenyan, WANG Yonghao, YU Yongzhao
2024, 46(6): 1362-1370. doi: 10.11781/sysydz2024061362
Abstract(52) HTML (11) PDF(6)
Abstract:
The identification of paleontological fossil types and their distribution provides important information for geochronological, paleoenvironmental studies, and oil and gas exploration. However, traditional fossil identification methods are time-consuming, labor-intensive, and highly dependent on manual efforts, making it difficult to meet the current demand for rapid exploration and evaluation. Given the limited number of spore and pollen fossil images, the complex classification of taxa, and the specific taxonomy of family, genus, and species, this research focused on improving the automation for fossil image processing, image screening, object detection, and classification. By utilizing techniques such as deep learning for object detection and label smoothing, the efficiency of fossil screening and spore and pollen fossil classification was significantly enhanced. Taking the identification of the Cenozoic spore and pollen fossils from the Bohai Sea shallow area as a case study, a set of intelligent identification methods was developed using neural networks such as YOLOv5 and DenseNet, with an average identification accuracy of 94%, basically meeting the practical accuracy requirements for fossil identification in production. The system could assist in the manual identification of paleontological fossils. By effectively combining various deep learning techniques with specialized knowledge in paleontology, the generalization ability and recognition accuracy of the identification model were improved from both data and model perspectives. Its successful application demonstrates the feasibility of artificial intelligence in the traditional field of paleontological fossil identification, reducing time and labor costs while providing accurate results.

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