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2022 Vol. 44, No. 1

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2022, 44(1): .
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Abstract:
Helium distribution of Dongsheng gas field in Ordos Basin and discovery of a super large helium-rich gas field
HE Faqi, WANG Fubin, WANG Jie, ZOU Yanrong, AN Chuan, ZHOU Xiaoyong, MA Liangbang, ZHAO Yongqiang, ZHANG Jin, LIU Dimin, JIANG Haijian
2022, 44(1): 1-10. doi: 10.11781/sysydz202201001
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With the developments of exploration and production of natural gas in the Dongsheng gas field of Hangjinqi area, northern part of Ordos Basin, industrial valued helium has been discovered in this area. Natural gases from 166 wells in the Dongsheng gas field were analyzed in this study and results show that the helium contents of these gases range from 0.045% to 0.487%, with an average value of 0.118%, indicating industrial value for the helium resource. Two basement-faults developed zones of Duguijiahan and Shiguhao in the center of the gas field have relative higher content of helium, with an average value higher than 0.1%, indicating a great exploration potential. The average helium contents decrease from the lower stratum (the first member of Xiashihezi Formation, P1x1) to the upper stratum (the third member of Xiashihezi Formation, P1x3), indicating that the P1x1 and P1x2 are potential targets for helium exploration and development. According to helium isotopic compositions, helium in the Dongsheng gas field has of a typical crust source, mainly from Archean-Proterozoic metamorphic rock-granite series in the basement. It is clear that helium distribution in the Dongsheng gas field was controlled by both basement lithofacies and deep fractures. Helium is enriched mainly along deep basement fractures such as Borjianghaizi and Wulanjilinmiao, and at the intersection of second-level fractures communicating helium source and fourth-level faults being migration pathways, and in the areas of Archean-Proterozoic metamorphic rock-granite series basement distribution. The variation of helium content with gas well production performance in short and medium term of key natural gas wells in the Dongsheng gas field showed that the helium contents in natural gases are stable in a relatively long term. The proved helium reserves are 244.4×106 m3 and the 3P reserves are approaching 830.4×106 m3 by volume method. Thus, the Dongsheng gas field is considered as the first supergiant helium-rich gas field in China. It is suggested that the Dongsheng gas field in the Ordos Basin should be regarded as a pilot test area for the development and utilization of helium resources, and the feasibility of building helium strategic reserve base should be accelerated. The research on helium accumulation mechanism, resource potential evaluation and comprehensive utilization of helium and other associated resources in natural gas should be strengthened in major oil and gas bearing basins, in order to guide the exploration, development and comprehensive utilization of helium resources.
Theoretical understanding of oil and gas accumulation in negative tectonic area and exploration practice
ZHAO Xianzheng, JIN Fengming, PU Xiugang, LUO Qun, ZHOU Lihong, HAN Guomeng, JIANG Wenya, DONG Xiongying, SHI Zhannan, HAN Wenzhong, ZHANG Wei
2022, 44(1): 11-23. doi: 10.11781/sysydz202201011
Abstract(808) HTML (191) PDF-CN(154)
Abstract:
A negative tectonic area refers to the relatively lower tectonic area from slope to deep depression in a basin. The theoretical understanding of oil and gas accumulation in the negative tectonic area is based on three accumulation models of "lithologic and stratigraphic reservoirs in the area of sag, lacustrine shale oil in deep depression, and coalbed methane in syncline area". Integrating with previous studies on reservoirs in negative tectonic area, a systematic knowledge system of oil and gas accumulation mechanisms and distribution laws in negative tectonic areas has been formed. The key points are as follows: (1) From the center to the margin of basin, oil and gas reservoirs are distributed in a circular order in the transverse direction, and enrich radially along dominant petroleum migration pathways in the longitudinal direction. (2) Due to different tectonic backgrounds, the sedimentary characteristics, hydrocarbon accumulation conditions, accumulation mechanism and distribution laws of negative tectonic area are greatly different from those of the positive tectonic area. (3) In deep depression and low slope, in situ hydrocarbon accumulation is dominant, and unconventional oil and gas distribution ring (inner ring) is formed. On medium and high slopes, passing oil and gas are captured, and lithologic and stratigraphic oil and gas distribution ring (central ring) is formed. While in positive tectonic area, oil and gas accumulate in high locations, and tectonic oil and gas distribution ring (outer ring) is developed. (4) An exploration idea based on the theory of oil and gas accumulation in negative tectonic area was proposed as follows. The target area should be integrately considered and exploration should be carried out from ring to ring. Migration pathways must be reguarded as a clue to seize oil and gas targets. The theory of oil and gas accumulation in negative tectonic area has effectively guided the discovery of a large number of subtle and unconventional oil and gas reservoirs in the slopes and deep sags of Jizhong and Huanghua depressions, and enriched the modern theory of oil and gas accumulation. It has an important practical guiding value for the exploration of deep complex subtle reservoirs and unconventional reservoirs in the negative tectonic area of basins.
Hydrocarbon generation and evolution characteristics of Triassic Zhangjiatan oil shale in southern Ordos Basin
GAO Bo, WU Xiaoling, ZHANG Ying, CHEN Xinjun, BIAN Ruikang, LI Qianwen
2022, 44(1): 24-32. doi: 10.11781/sysydz202201024
Abstract(799) HTML (203) PDF-CN(117)
Abstract:
The Zhangjiatan oil shale from the Upper Triassic Yanchang Formation in the southern Ordos Basin is an important solid mineral resource, it can also be considered as the main source rock of Triassic oil and gas in the basin. Results of analytical experiments such as TOC, bitumen extraction and group composition, oil content etc. of shale samples from key typical outcrop sections and drilling cores showed that the Zhangjiatan oil shale has a high organic matter abundance. The TOC content ranges 5.11% to 36.47%, with an average value of 16.15%. The S0+S1+S2 value distributes between 16.58-230.98 mg/g, with an average value of 94.20 mg/g. The extracted bitumen abundance is between 0.42%-2.22%, with an average value of 1.25%. Based on these analytical results, Zhangjiatan oil shale can be assigned to be high-quality source rock with an excellent hydrocarbon generation potential. The oil content of oil shale is between 3.52% and 14.6%, with an average value of 8.16%, which belongs to medium- and high-quality oil shale. The kerogen type is mainly Ⅰ-Ⅱ1, and the Ro value generally ranges from 0.43% to 1.09%. Based on field outcrop and drilling core samples, a thermal evolution profile of the Zhangjiatan oil shale in the southern Ordos Basin was established. Moreover, the oil contents of oil shale before and after solvent extraction were compared, and the variations of oil content and pyrolysis hydrocarbon products during the thermal evolution of oil shale were analyzed. There are two types of resources such as oil shale and shale oil in the Zhangjiatan oil shale with a great potential in the southern Ordos Basin. Moreover, some exploration and development countermeasures of oil shale and shale oil were put forward.
Fractal characteristics and its controlling factors of pore-throat with different scales in tight sandstones of the Yanchang Formation in the Ordos Basin
WANG Wei, CHEN Zhaobing, XU Shuang, LI Yahui, ZHU Yushuang, HUANG Xingyuan
2022, 44(1): 33-40. doi: 10.11781/sysydz202201033
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Abstract:
Pore-throat structure is one of the important factors affecting the characteristics of tight sandstone reservoirs. Pore-throat structure of tight sandstone is complex and with strong heterogeneity, thus, conjunction study with fractal theory bas become a promising approach. In this study, casting thin section, scanning electron microscopic observation and rate-controlled porosimetry were performed on tight sandstone samples of the Yanchang Formation in the Ordos Basin to study the distribution of pores and throats. With fractal principle and method, the fractal dimensions and influencing factors of tight sandstone pores and throats were studied. Results showed that there are clear inflection points on the fractal curves of lgSHg versus lgPc, and according to the mercury pressure corresponding to the inflection points of fractal curves, pores and throats of tight sandstones can be classified to be large and small ones respectively. Fractal dimensions (D) were calculated by the means of slope of the straight part of each curve, and the fractal dimensions of pores and throats greatly varied between large pore-throats and small pore-throats. For the small pore-throats, compaction and cementation effects are strong, mainly developing intercrystalline pores, residual intergranular pores and necked throats. The heterogeneity of small pore-throat is weak, the pore-throat space is less deformed, and the fractal dimensions are small (2 < D < 4). For the large pore-throats, dissolution effect is strong, mainly developing curved lamellar throats, dissolved pores and composite pores. The storage space of large pore-throats is large, and the deformation of large pore-throats is significantly affected by diagenesis. Thus, the heterogeneity of large pore-throat is relatively stronger and the fractal dimensions of large pore-throat are higher (D > 7). It was indicated that diagnosis, including compaction, cementation and dissolution, greatly affected the size and shape of pore-throat in tight sandstone, and determined the fractal characteristics of pore-throat with different scales.
Characteristics and genesis of fractures in Middle Ordovician Majiagou Formation, Daniudi Gas Field, Ordos Basin
PENG Xianfeng, DENG Hucheng, HE Jianhua, LEI Tao, ZHANG Yeyu, HU Xiaofei
2022, 44(1): 41-50. doi: 10.11781/sysydz202201041
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Abstract:
The Daniudi Gas Field in the Ordos Basin has great natural gas potential, but a variety of fractures with complex origins was developed in the weathering crust karst reservoirs in the Middle Ordovician Majiagou Formation. In order to study the characteristics of fractures in the reservoirs, petrology and logging techniques were used to compare the differences between the fractures caused by steep ridges and structural fractures in terms of fracture development frequency, effectiveness, period, occurrence layer, shape, dip angle, etc. With elastic theory and fracture mechanics theory, the stress component at the end of fractures was analyzed, and the cause of the steep ridge fractures was discussed. Results show that the fractures caused by steep ridges are mainly vertical fractures and high-angle fractures. The fracture extension direction and fracture shape are irregular, and the fracture surface is uneven, with the characteristics of wide top and narrow bottom, and no bifurcation at the tail end. There is dissolution between the fractures, which is in a non- to semi-filled state, and the effectiveness of the fractures is high. The steep ridge fractures were controlled by factors such as ancient steep slope angle, rock layer inclination, initial fracture density and rock mechanical properties. Compared to structural fractures, the steep ridge fractures are more favorable for hydrocarbon migration. Studying the characteristics and causes of steep ridge fractures will help to further understand the distribution of weathered crust karst reservoirs, and identify favorable areas for the next exploration and development of the Daniudi Gas Field.
Accumulation characteristics of continuous sand conglomerate reservoirs of Upper Permian Upper Wuerhe Formation in Manan slope area, Junggar Basin
HUANG Liliang, WANG Ran, ZOU Yang, WAN Min, CHANG Qiusheng, QIAN Yongxin
2022, 44(1): 51-59. doi: 10.11781/sysydz202201051
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A large continuous conglomerate reservoir has been recently discovered in the Upper Permian Upper Wuerhe Formation on the southern slope of Mahu Sag, Junggar Basin. In order to timely summarize, enrich and develop the theory of continuous oil and gas geology, and to provide a basis for deepening regional exploration, it was studied in this paper the reservoir forming elements and reservoir characteristics based on the fine structure interpretation, sedimentary system study and reservoir-cap combination analysis of these reservoirs. The results showed that the source rocks of Fengcheng Formation on the southern slope were widely distributed, with a large thickness, good type and high maturity. In four major material source systems including Zhongguai, Karamay, Baijiantan and Dabasong fans, the sand conglomerate reservoirs in the first and second members of Upper Wuerhe Formation overlapped continuously, and formed a stable reservoir-caprock assemblage with the widely developed mudstone caprock of the third member of Upper Wuerhe Formation. Near EW-oriented deep strike-slip faults and unconformities widespread in the sag provided pathways for hydrocarbon migration and accumulation. The Upper Wuerhe Formation is a "foreland-depression" replacement-type deposit. Under the background of large formation pinch-out zone, a large area of continuous lithologic traps was developed, forming stratigraphic, lithologic and fault-lithologic oil reservoirs. The Zhongguai and Karamay fans are found to have a high potential for exploration and still have many remaining oil and gas points. The Baijiantan and Dabasong fans have similar sedimentary background with the Zhongguai fan, and have a lower exploration degree, which are key area for future exploration.
Characteristics and exploration potential of porous reservoirs in 4th to 5th members of Lower Triassic Jialingjiang Formation in southwestern Sichuan Basin
LIAO Rongfeng, TANG Jing, SONG Xiaobo, HAO Zhemin, WANG Wenkai, LIU Yong
2022, 44(1): 60-70. doi: 10.11781/sysydz202201060
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Abstract:
The main body of Lower Triassic Jialingjiang Formation in the Sichuan Basin is a set of cratonic platform facies deposits. It is characterized by shallow burial depth, thin reservoir thickness and good gas-bearing property in the southwest. Some small- and medium-scale gas reservoirs such as Maliuchang, Moxi and Chishui were discovered in the early stage. In the southwestern Sichuan exploration zone of SINOPEC, a gas production of 2.32×104 m3/d has been discovered in the 4th member of Jialingjiang Formation in well JS 1 in Jingyan area, and a gas production of 5.58×104 m3/d has been discovered in the 5th member of Jialingjiang Formation in well JH 1 in Weiyuan area in recent years. In order to further clarify the distribution of pore-type reservoirs in the Jialingjiang Formation in the southwestern Sichuan Basin and favorable target areas for further exploration, the pore-type reservoirs of the 4th and 5th members of Jialingjiang Formation were evaluated in this study based on the analyses of regional geological characteristics, drilling core cuttings, casting thin sections and experiments. The pore-type reservoirs are found to be mainly distributed in the 1st section of the 4th/5th member of Jialingjiang Formation. Both limestones and dolomites were developed. Vertically, (grey) dolomitic flat and granular beach superimposed in multiple periods. The main rock types of the reservoirs are crystalline dolomite, granular dolomite and granular limestone. The pore structure of high-quality reservoirs is characterized by large pores with medium throat, large pores with fine throat, and medium pores with fine throat. Favorable sedimentary microfacies such as dolomitic flat and granular beach controlled the distribution of reservoirs. Quasi-contemporaneous dissolution was the key to the formation of high-quality pore-type reservoirs. Fluid charging in the Indosinian and mid-late Yanshanian resisted the destruction of pores caused by later diagenetic compaction and cementation. The areas of Jingyan, Rongxian-Yibin and Weiyuan on the western margin of Luzhou paleo-uplift are favorable targets for future exploration.
Characteristics of ultra-deep shale reservoir of marine-continental transitional facies: a case study of lower member of Upper Permian Longtan Formation in well Y4, Puguang Gas Field, northeastern Sichuan Basin
LI Jin, WANG Xuejun, ZHOU Kai, WANG Yunsuo, LI Ningchao, WU Ying, WANG Meige
2022, 44(1): 71-84. doi: 10.11781/sysydz202201071
Abstract(933) HTML (332) PDF-CN(68)
Abstract:
In order to explore the characteristics of marine-continental transitional shale reservoir under overburden conditions, studies of organic geochemistry, mineral composition, parameters of pore structure and physical properties of shale in well Y4 of the Upper Permian Longtan Formation in the Puguang exploration area of northeastern Sichuan Basin were carried out. The shale of the Longtan Formation is characterized by high abundance of organic matter (ranging from 3.77% to 10.72%), humic and sapropelic organic matter (kerogen type of Ⅱ2 to Ⅲ) and post stage of maturation (%Ro values ranging from 3.82% to 3.97%). The average pore volume, specific surface area and porosity of shale are 0.047 mL/g, 31.8 m2/g and 6.64%, respectively. Reservoir space is mainly composed of organic pores, interlayer pores of clay minerals, dissolution pores of brittle minerals and micro fractures. The main pore structure is parallel plate-shaped pores and open tubular pores at both ends. The porosity of shale is positively correlated with the contents of TOC, pyrite and quartz in deep-water lagoon environment, which indicated that the original mineral composition and structure were controlled by anoxic reduction and stable water environment. Meanwhile, the effective complexation of rigid mineral particles with organic matter and clay minerals provided necessary conditions for the preservation of organic pores. Reservoir network is consisted of flat organic macropores affected by flattening transformation, densely-developed organic pores, intergranular pores and fractures of brittle minerals, and finally formed ultra-deep shale reservoir deposited in deep-water lagoon microfacies.
Geological characteristics and seismic fine description of different types of sand bodies in Jurassic Shaximiao Formation in central Sichuan Basin
FU Lei, ZHANG Benjian, CAO Zhenglin, HUANG Dong, BAI Rong, LI Yucong, WANG Xiaolan
2022, 44(1): 85-93. doi: 10.11781/sysydz202201085
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Abstract:
Sand bodies in the Jurassic lacustrine-fluvial sedimentary system in the Sichuan Basin are realistic objects of shallow tight oil and gas exploration and development. Due to the influence of sedimentary microfacies, sand bodies have geological characteristics such as type diverse, variable lithology, significant thickness variation, and strong heterogeneity. Therefore, the fine description and prediction of different types of sand bodies is the current bottleneck for exploration and development. Based on the classification of various sand group types of the 1st member of Jurassic Shaximiao Formation, reservoir analysis was carried out, logging and geophysical response characteristics were concluded, and fine identification and spatial prediction were made by time-sharing window. Results show that: (1) The 1st member of Shaximiao Formation can be divided into 5 sand groups, among which the 1st sand group is mainly littoral-shallow lacustrine sheet sand and beach bar sand, and the 2nd to 5th sand groups are delta front facies channel-plain channel; (2) The average porosity of channel sand is 4.68%, which is significantly higher than that of bottom sheet sand (3.1%). The physical properties of the Ⅰ channel are the best, followed by the Ⅳ, Ⅱ, and Ⅲ channels. (3) The prediction standard of channel sand is: natural gamma < 65 API, and the prediction standard of sheet sand locates between 65 and 75 API. In sand body prediction, for sheet sands (beach bars), the study time window is extracted to be within 0-20 ms, and for river channels, the study time window is in the range of 20-100 ms upwards from the bottom of the Shaximiao Formation. Finally, a set of methods suitable for fine description and prediction of different types of sand bodies in the lacustrine-fluvial sedimentary system was established.
Resource evaluation and sweet-spot prediction of inter-salt shale oil of Paleogene Qianjiang Formation, Qianjiang Sag, Jianghan Basin
WANG Shaohua, NIE Hui, MA Shengzhong, DING Yi, LI Hao, LIANG Wenhua
2022, 44(1): 94-101. doi: 10.11781/sysydz202201094
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Shale oil resources are rich in China's continental basins, and is a new reliever of petroliferous resource in China. It is of great practical significance for shale oil exploration in continental basins in eastern China to strengthen the study on the evaluation of shale oil resource potential in continental salty lake basins. For this reason, the inter-salt shale oil of Paleogene Qianjiang Formation in Qianjiang Sag of Jianghan Salt Lake Basin was employed as an example. This paper highlights the effectiveness and innovation of resource evaluation, and optimizes the shale oil resource evaluation method based on TSM basin modelling method, supplemented by volume method and pyrolytical method and resource abundance analogy method, so as to further clarify the resource potential and favorable area distribution of shale oil. The inter-salt shale oil resources of the Qianjiang Formation in the Qianjiang Sag are mainly distributed in 13 single rhythm layers and 1 complex rhythm layer, with the predicted geological resources of 800 million tons and recoverable resources of 126 million tons, of which the Eq34-10 rhythm resource is the largest. Horizontally, it is predicted that the central and northern part of Qianjiang Sag is a favorable exploration area for shale oil in the Qianjiang Formation, in which the geological resources of sweet-spot area are 243 million tons and the recoverable resources are 38 million tons, the geological resources of favorable area are 557 million tons and the reco-verable resources are 88 million tons.
Exploration advances and accumulation model for Neocene lithological reservoirs in Laibei Low Uplift, Bohai Sea area
WEN Honglei, YANG Haifeng, YANG Bo, WANG Liliang, TU Xiang, LI Zhiqiang
2022, 44(1): 102-111. doi: 10.11781/sysydz202201102
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Abstract:
The Laibei Low Uplift locates in the southern part of Bohai Sea area, and is sandwiched by two major hydrocarbon-rich sags with a complex structural evolution history. The broken fault block traps and the model of hydrocarbon accumulation are still unclear. It is the single uplift (low uplift) without commercial development in the Bohai Sea area. Combined with recent drilling data, a "convergence-transportation-filling (CTF)" model of the Neocene lithological reservoir formation in the Laibei Low Uplift was proposed. The type of convergence determines the enrichment zone of oil and gas on the uplift, and the zones of "fault convergence type" and "structural ridge convergence type" enrichment are developed in the eastern and western sections of the Laibei Low Uplift. The vertical migration efficiency of oil and gas appeared to be determined by the activity of oil source fault. When the fracture slip of the migration fault in the drilled trap is greater than 80 m, the shallow layer is generally found to be a better reservoir of oil and gas. The relationship between fault and sand restricts the filling efficiency of oil and gas. When the contact area of fault and sand is greater than 10×103 m2, the Neocene traps generally have a better oil and gas abundance and hydrocarbon column height. By the using of established reservoir forming model, a comprehensive analysis of the undrilled lithological traps of Neogene strata was carried out by this study, 23 favorable target sand bodies were suggested and have been proved to be successful. The effectiveness of the reservoir forming model has been validated, and the first large-scale commercial oil field, i.e., Kenli 6-1 oil field, on the Laibei Low Uplift has been accordingly developed.
Geochemical characteristics and genetic analysis of crude oils in Mosuowan area, Junggar Basin
LI Erting, CHEN Jun, CAO Jian, WEI Xia, ZHANG Yu, ZHANG Xiaogang, WANG Haijing
2022, 44(1): 112-120. doi: 10.11781/sysydz202201112
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Abstract:
Analysis of the biomarkers of saturated hydrocarbon and related compound specific carbon isotopes of crude oils were carried out for the research of origin of oils and controlling factors of oil properties in the Mosuowan area of the Junggar Basin, and mixed-source oil simulation was also carried out to reveal hydrocarbon accumulation in the study area. The carbon isotope of crude oil in the Pen 5 well block is relatively heavy, the Pr/Ph value is higher, between 1.4 and 1.9, and the index of adamantane isomerization is greater, indicating that the oil maturity of the Pen 5 well block is higher than that of the Pencan 2 well and had a more oxidative sedimental environment. The C7 light hydrocarbons of oil of the Mosuowan area are dominated by methylcyclohexane, with a content over 40%, and the distributions of regular steranes are dominated by C29 homologues with a content over 40%. Crude oils in the study area are thus indicated to be generated from terrestrial partial humus source rocks. The carbon isotope compositions and distribution of n-alkanes in the Pen 5 and Pencan 2 well blocks are similar, indicating that they were from the comparable sources, and they are generally similar to the source rocks in the Lower Wuerhe Formation. But the carbon isotope values of n-alkanes with different carbon numbers in the source rocks of the Lower Wuerhe Formation have a large span, reaching 4.6‰, while the carbon isotope values of n-alkanes with different carbon numbers of crude oil in the Mosuowan area have a smaller span, between 2.2‰ and 3.0‰. It is mainly caused by the different mixing ratio of crude oil. The quantitative calculation results of biomarkers in mixed-source oil showed that crude oil in the Mosuowan area was mainly derived from the late high-maturity source rocks in the Lower Wuerhe Formation, mixed with those from the early mature source rocks in the Fengcheng Formation. Among them, the high-maturity source rocks in the Lower Wuerhe Formation have a relatively greater contribution to crude oil in the Pen 5 well block, around 80%, and contribute about 60% to crude oil in the Pencan 2 well block. As a result, it is concluded that different proportions of mixed sources are the main reason which caused differences in the geochemical characteristics of crude oil in the Mosuowan area.
Carbon isotopic evolution of hydrocarbon gases generated from carbonate source rocks via different thermal simulation methods
CHEN Lei, ZHENG Lunju, HUANG Haiping, NING Chuanxiang
2022, 44(1): 121-128. doi: 10.11781/sysydz202201121
Abstract(742) HTML (292) PDF-CN(61)
Abstract:
Chinese marine source rocks are generally at the stage of high- to over-mature, there are still some uncertainties about whether the existing hydrocarbon isotopic indexes can be directly employed to distinguish the genetic types of marine carbonate natural gas and consequently, gas-oil source correlation can be carried out. In this paper, a series of pyrolysis experiments for hydrocarbon generation with different conditions were carried out using the low-maturity marine carbonate source rocks of Luquan Ⅱ1 type in Yunnan province to analyze the carbon isotope of the collected gas products. The results showed that: ①During the entire thermal evolution stage, the carbon isotope values of kerogen did not vary significantly with the increasing of maturity, while the carbon isotope values of methane and ethane both decreased and then increased with the increase of maturity, showing similar evolution characteristics. In the main oil and gas generation stage, it is significantly smaller than the isotope value of its parent material kerogen. In the over-mature stage (VRo ≥2.2%), the tendency of carbon isotope of ethane to become heavier is obviously accelerated, even greater than the carbon isotope value of its parent material kerogen, showing the characteristics of "coal-type gas". This suggested that we need to be cautious when simply using the carbon isotope values of methane and ethane to identify the type of natural gas. ②At the same maturity, the carbon isotope values obtained from the pyrolysis experiment of semi-closed and semi-open system are lighter than those obtained from the pyrolysis experiment of closed system. This indicates that conventional natural gas reservoirs formed by the discharge of hydrocarbon gas from the same source rock have a certain difference between the carbon isotope values of hydrocarbon gas and the carbon isotope values of shale gas retained in the source, showing the characteristics of "different sources". Attention should also be exercised to the use of carbon isotope templates or regression formulas to carry out gas-source comparisons. ③With the two pyrolysis methods, the carbon isotope value of methane is always lighter than that of ethane in the full evolution stage of the same source rock. This indicated that conventional natural gas reservoirs formed by direct gas supply from single set of source rock do not have "inversion" phenomenon of methane and ethane carbon isotopes.
Characteristics of reservoir fluid inclusions and hydrocarbon charging process in the Dawangzhuang buried hill zone of Jiyang Depression, Bohai Bay Basin
ZHANG Zhiqing, LIU Hua, MA Lichi, LIU Jingdong, GUO Zhiyang
2022, 44(1): 129-138. doi: 10.11781/sysydz202201129
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The Dawangzhuang buried hill zone is a typical representative of Paleozoic oil and gas exploration in the Jiyang Depression, Bohai Bay Basin, and has experienced a complicated accumulation process. Using petrographic observation, microthermometry and abundance of hydrocarbon inclusions, the Paleozoic hydrocarbon charging process in Dawangzhuang buried hill zone was discussed. The study shows that the Paleozoic reservoirs developed hydrocarbon inclusions in the study area. Ordovician hydrocarbon inclusions with pale yellow and blue-green fluorescence distributed along the calcite veins and particle healing joints. Asphalt inclusions and oleaginous are only distributed in Dagu 671 oil reservoir with a small scale. The main peaks of the homogenization temperature are from 80 ℃ to 90 ℃ and from 100 ℃ to 110 ℃; Carboniferous-Permian hydrocarbon inclusions with blue-green fluorescent distributed along the micro-cracks of quartz particles and secondary enlarged edges. The main peak of the homogenization temperature is from 100 ℃ to 110 ℃. Combining with the hydrocarbon generation and expulsion periods of source rocks, it can be concluded that there are two stages of hydrocarbon charging in the Paleozoic in the study area. The first stage of oil and gas charging occurred in the late Dongying period (27~25 Ma), which was a small-scale accumulation of Paleozoic, mainly in the Ordovician; the second stage of oil and gas charging occurred from the end of Guantao period to the end of Minghuazhen period (5~2 Ma), which was a large-scale accumulation of Ordovician and Carboniferous-Permian. The development of asphalt inclusions near the Dagu 671 well area and the fact shown by the Effective Grids containing Oil Inclusions (EGOI) that the ancient oil-water interface is lower than the current one are related to the activity of the Da 1 fault at the end of the Minghuazhen period (2 Ma), resulting in local adjustments and smaller scope of oil and gas reservoir.
Quantitative assessment of source rock maturity with multiple aromatic parameters: a case study of Mesozoic source rocks in Yingen-Ejinaqi Basin
CHEN Zhijun, ZHANG Yaxiong, WANG Yongchang, WANG Xi, GE Hongxuan, GAO Zhiliang, LI Ziliang
2022, 44(1): 139-149. doi: 10.11781/sysydz202201139
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Abstract:
Aromatic parameters have been widely applied to assess the maturity of organic matters. Some parameters may not only be affected by maturation, but also more affected by organic matter source, sedimentary environment, etc. Therefore, the application effect of some parameters in some study areas were not satisfying, and the previous relational expression to calculate the vitrinite reflectance (Rc) which only based on a single parameter is also not suitable for other areas. In this study, we proposed a method to improve the accuracy of using multiple aromatic parameters to quantitatively evaluate source rock maturity. This method was based on a certain number of GC-MS analysis data of aromatic fractions of source rocks in the study area, to find out a most sensitive parameter to maturity in three categories of aromatics (alkyl naphthalene series, alkyl phenanthrene series and alkyl dibenzothiophene series) respectively. Here the most sensitive parameter meant having the largest correlation coefficient to Ro in certain category. Then a multiple linear regression equation was established among these three parameters and Ro using a numerical analysis software, and with this equation Rc can then be calculated with multiple parameters. This method is applied to the study of Mesozoic lacustrine source rocks in the Hari Sag of Yingen-Ejinaqi Basin, the organic matter types of these source rock are mainly type Ⅱ1-Ⅱ2. The results indicated that the correlation coefficient (Rc) between Ro and Rc which was calculated by established formula was as high as 0.96, and compared with the single aromatics parameter, the correlation coefficient has been considerably improved.
A comparative study on the geochemical characteristics of expelled and retained oil from hydrocarbon generation simulation of Australian Tasmanian oil shale Ⅰ: fraction and isotopic compositions
LIN Jingwen, XIE Xiaomin, WEN Zhigang, WU Fenting, XU Jin, MA Zhongliang, ZHANG Lei
2022, 44(1): 150-159. doi: 10.11781/sysydz202201150
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Australian Lower Permian Tasmanian oil shale is rich in organic matter with relatively lower maturity, and the bio-precursor of organic matter is dominated by Tasmanite. Thus it is an ideal sample for thermal simulation experiment. In order to study the compositional characteristics and thermal evolution characteristics of expelled and retained oil, artificial simulation experiments were carried out. Results show that the peak temperature for oil generation of Tasmanian oil shale is ~340 ℃. Taking the peak temperature of 340 ℃ as a boundary, the relative content of oil fractions at each temperature showed that, the content of saturated hydrocarbon and aromatic hydrocarbon decreased with the increase of temperature before 340 ℃, but increased with the increase of temperature after the peak point. The content of polar fraction and asphaltene is opposite to that of saturated aromatic fractions. The content of saturated hydrocarbon in expelled oil is higher than that in retained oil, and the content of aromatic hydrocarbon in retained oil is obviously higher than that in expelled oil. Stable carbon isotopes of the fractions of both expelled oil and retained oil have been reversed. Aromatics appeared to have the heaviest isotope, followed by saturated hydrocarbons and non-hydrocarbons. Asphaltenes generally have the lightest isotopic values. In the whole simulation process, the carbon isotope composition of retained oil is heavier than that of expelled oil, and the aromatic carbon isotope is the most stable, indicating that it is an effective indicator of oil source comparison. If the residual hydrocarbon shale in autoclave is taken as a shale oil system after hydrocarbon generation simulation, the oil saturation index (OSI) value of the shale samples in the autoclave after thermal simulation is the highest near the peak of oil generation, suggesting that maturity is one of the important factors affecting the exploration of shale oil.
Characterization of the length of structural fractures in low permeability reservoirs and its application: a case study of Longwangmiao Formation in Moxi-Gaoshiti areas, Sichuan Basin
SUN Ke, XU Ke, CHEN Qinghua
2022, 44(1): 160-169. doi: 10.11781/sysydz202201160
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In order to classify the quantitative characterization method of structural fracture length in low-permeability reservoirs, the Cambrian Longwangmiao Formation of Moxi-Gaoshiti areas in the Sichuan Basin is taken an example in this study. The relationship between structural fracture lengths of low-permeability reservoirs was derived from the perspective of structural stress field by the means of core fracture statistics and rock mechanical experiment. Quantitative relationships between fracture length and fracture volume density, strain energy density and rock mass stress state were established. Results showed a negative exponential power relationship between fracture length and number, a proportional linear relationship between fracture volume density and strain energy density, and a negative exponential power relationship between fracture length and volume density. The derived fracture length formula was applied to the Longwangmiao Formation in Moxi-Gaoshiti areas. Numerical simulation results showed that fracture density generally ranges from 1-5 m2/m3, and the highest value is 9 m2/m3, mainly distributed in fault and its surrounding areas. Fracture length is mainly between 1-20 m. The fractures in fault and surrounding areas are dense and short, usually less than 3 m.
Distribution and genetic mechanisms of connected pore systems in continental shale reservoirs: a case study of Xujiahe Formation of Upper Triassic, Western Sichuan Depression
ZHAO Mingzhu, YANG Wei, WANG Yaohua, LU Jiankang, XU Liang, LI Lan, LI Xingyu, YAO Linjie
2022, 44(1): 170-179. doi: 10.11781/sysydz202201170
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The distribution and genetic mechanisms of connected pore systems in continental shale reservoirs were analyzed in this paper to enhance the high-efficiency exploration of shale gas. A case study was made with the continental shale of the Upper Triassic Xujiahe Formation in the Western Sichuan Depression. Various experimental methods such as X-ray diffraction, field emission-scanning electron microscopy, low temperature gas adsorption, high-pressure mercury injection and nuclear magnetic resonance cryoporometry were applied to study its mineral composition, distribution of pore-size and pore connectivity, and the main constrains for pore connectivity were discussed. The continental shale of the Xujiahe Formation in the study area has a high content of clay minerals, followed by quartz. The pore-size distribution is complex, and the mesopores in the range of 4-50 nm is the main contributor to pore volume (87.33%) and specific surface area (49.19%). The pores having the size between 20-50 nm appeared to have better pore connectivity and are the major type of connected pores. The continental shale developed various types of pore, predominantly composed of clay intercrystalline pores, with minor dissolved pores and organic pores. Microfractures were widely developed and formed the dominant connective pore assemblage together with clay intercrystalline pores. The development and distribution of connected pores were controlled by the contents and arrangement of brittle minerals such as clay minerals and quartz. Based on the experimental results, some development mechanisms of connected pores in continental shale were concluded. The combination of intercrystalline pores and microfractures developed on the matrix of clay minerals and brittle minerals shows the best connectivity, followed by the clay intercrystalline pores in clay minerals, while the organic pores and clay intercrystalline pores in organic-clay complexes show the lowest connectivity.
Characteristics of methane isothermal adsorption of deep shale from Lower Silurian Longmaxi Formation in southeastern Sichuan Basin and its geological significance
WANG Qiang, MU Yapeng, CHEN Xian, SONG Zhenxiang, MA Zhongliang, QIU Qi
2022, 44(1): 180-187. doi: 10.11781/sysydz202201180
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Breakthrough of the exploration of deep shale gas in the Sichuan Basin, Southwest China, has been achieved for decades, there are still some controversies about the adsorption performance and occurrence state of shale gas in deep strata. Isothermal adsorption experiments were carried out under high temperature and high pressure with typical shale samples from deep stratum of the Lower Silurian Longmaxi Formation in Fuling and Dingshan areas in the southeastern Sichuan Basin. Results show that there is a big difference between absolute adsorption and excess adsorption, thus, it is proposed that the excess adsorption capacity should be corrected to the absolute adsorption capacity when evaluating the adsorption performance of deep shale gas. After correction, the variation of absolute shale adsorption with pressure appeared to have three stages including "rapid rise", "slow rise" and "steady rise". The absolute adsorption capacity of deep shale samples from Fuling and Dingshan areas is higher than 2.0 m3/t at 110℃ and 70 MPa, and combined with the adsorption and free gas ratios of deep shale, the total gas content is more than 4.0 m3/t, indicating that deep shale may still have good adsorption performance under high temperature and high pressure. The evaluation of deep shale adsorption capacity can provide reliable parameters for the study of shale gas content and the evaluation of resource potential and reserve for shale gas. Considering the difference of ratio of free gas to adsorbed gas between deep shale and shallow-medium shale, different exploration and production methods can be adopted to effectively improve the production capacity and production cycle of shale gas.
Erosion thickness recovery and its significance to hydrocarbon accumulation in northwestern Qaidam Basin
FENG Dehao, LIU Chenglin, TIAN Jixian, TAI Wanxue, LI Pei, ZENG Xu, KONG Hua
2022, 44(1): 188-198. doi: 10.11781/sysydz202201188
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The area from the northwestern Qaidam Basin to Yiliping is large and the exploration degree of proved petroleum reserves is low. It is of great significance for future petroleum resource assessment to recover the thickness of eroded formation. In this paper, several methods including stratigraphic trend extension, interval transit time, vitrinite reflectivity and Easy%Ro optimization were used to calculate the formation erosion thickness during the late tectonic movement in the study area, and its significance for hydrocarbon accumulation was quantitatively discussed. The Quaternary and Pliocene Shizigou Formation (N23) in the study area were generally eroded, with a maximum erosion thickness of about 1 000 m on the top of some local structures. The Upper Youshashan Formation (N22) was eroded on the top of some structures such as Youquanzi, and the Lower Youshashan Formation (N21) was eroded only at the periphery of the basin. The Yingxiongling structural belt, the top of each structure and the Altun foreland are the areas experienced the most serious erosion, generally more than 500 m of thickness. The erosion thickness in the depression and the eastern part of the study area is relatively smaller, usually less than 500 m, and the tectonic activities here are relatively stable. The distribution of petroleum reservoirs and hydrocarbon shows are closely related to the erosion thickness of sedimentary strata. The erosion thickness with appropriate strength (300-1 500 m) is conducive to the formation of oil and gas reservoirs, while an erosion thickness over 1 500 m is easy to cause damage to oil and gas reservoirs.
2022, 44(1): 199-199.
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