石油实验地质

2021, 43(2): .

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Characteristics and environment indication of mud shale undergone low temperature metamorphism: a case study of Neoproterozoic Binggounan Formation, Hongliugou Ⅰ section, Altyn Tagh fault

QIAN Yixiong, CHU Chenglin, LI Yuejun, WANG Yi, ZHANG Zhongpei, YANG Xin, LI Wangpeng, MA Hongqiang, CHEN Yue, SHAO Zhibing, ZHUANG Xinbing

2021, 43(2): 193-207. doi: 10.11781/sysydz202102193

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The Neoproterozoic Binggounan Formation mud shale in the Hongliugou Ⅰ section on the northwestern margin of the Altyn Tagh fault was deposited in a passive continental margin. They are shelf sediments about 60 m thick, interbedded with siliceous rocks, undergone a low temperature thermodynamic metamorphism, and had hydrocarbon generation potential. The tectonic background, provenance, weathering and sedimentary environment of the mud shale were discussed with regard to stratigraphic sections, mineralogy and geochemical analyses. The mud shale was mainly composed of silica-rich clay rock and mud-rich siliceous shale, followed by mud-silica mixed shale. They have simila-rities in Si, Mg, K, P, Sc, Y, Hf, Th Sc contents compared with the Post Archaean Australian shale (PAAS). The Ti, Mn, Fe, Ta contents and δEu_n, δCe_n, ΣREE values are higher, while the Al, Ca, Na, Nb and Zr contents are lower. The primitive sediment sources of the Binggounan mud shale were recycled sedimentary clasts, intermediate mafic and acid intrusive rocks, similar to a normal shale and arenites argillites and ensialic of continental upper crust in composition. The shale has undergone moderate chemical weathering in warm and humid conditions. The formation was divided into three sedimentary cycles from bottom to top, mainly anaerobic and anoxic, and occasionally oxidized. Hydrothermal alteration also occured in the lower section. The mud shale with a clay content of about 40% is rich in trace elements (REE) and organic matter, which was deposited in a suboxic to anoxic section on the shelf, showing a high productivity and hydrocarbon-generation potential.

Geological background and exploration prospects for the occurrence of high-content hydrogen

MENG Qingqiang, JIN Zhijun, SUN Dongsheng, LIU Quanyou, ZHU Dongya, LIU Jiayi, HUANG Xiaowei, WANG Lu

2021, 43(2): 208-216. doi: 10.11781/sysydz202102208

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Gas of hydrogen is combustible and has been regarded as one of the important form of clean energy. With the increasing environmental concerns caused by the continues and high dependence on fossil fuels, more attention is being paid to the research on hydrogen exploration. However, only limited understanding about the geological, genetic as well as distribution characteristics of hydrogen gas has been addressed. In this paper, the formation and enrichment mechanisms of hydrogen gas under different geological conditions were compared, results showed that reservoirs of high-content hydrogen gas may develop in rift system and the front edge of plate subduction zone. By further summarizing the distribution of hydrogen gas in different tectonic members, it is concluded that the plate collision zone and subduction zone and their peripheries controlling the distribution of the development of high-content hydrogen gas and thus the petroliferous basins developed in these tectonic positions have good natural gas preservation conditions, hence are promising for the preservation of high-content hydrogen gas.

Sedimentary characteristics and development model of Cambrian gypsum-salt rocks, Tarim Basin

FAN Qi, FAN Tailiang, LI Qingping, DU Yang, ZHANG Yan, YUAN Yaxuan

2021, 43(2): 217-226. doi: 10.11781/sysydz202102217

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The Cambrian gypsum-salt rocks in the Tarim Basin are key geological elements to the pre-salt play typical marine evaporites, yet little attention has been paid to this set of evaporites. Based on a field survey, the latest 2D seismic interpretation and comprehensive analysis of sixteen exploratory wells, a study on the sedimentary characteristics of gypsum-salt rock was carried out in a progression of "point to line, and to plane", and a contour map of the Lower to Middle Cambrian cap rocks, gypsum-salt rocks and the sedimentary facies maps of the Awatag Formation were compiled. A development model of "dry and hot paleoclimate, continuous regression process, reef barrier background" of the Lower to Middle Cambrian gypsum-salt rocks was established. There are four sets of gypsum-salt rocks with four lithofacies combinations developed longitudinally and stably in the Wusongger and Awatag formations. The gypsum-salt rocks in the regression stage are featured by "inner salt, middle gypsum, outer red-layer", while those in the transgression stage are interbedded with gypsum, mudstone and dolomite. The average thickness of the Lower to Middle Cambrian cap rocks in the Tarim Basin is 245 m, and the average thickness of the gypsum-salt rocks is 167 m (340 m maximum), showing good sealing capacity. The arid-hot paleoclimate, continuous regression and reef and reef barrier provided favorable conditions for the development of thick gypsum-salt rocks in the Early to Middle Cambrian of the Tarim Basin. The paleoclimate and sea level change restricted the facies boundary between limited platform and evaporation platform, and made the Bachu Uplift and Awati Sag (the stable thickness of gypsum-salt rocks is over 300 m) become the salt accumulation center at that time.

Optimization of multi-layer commingled coalbed methane production in Zhijin area, Guizhou province

GAO Yuqiao, GUO Tao, HE Xipeng, GAO Xiaokang

2021, 43(2): 227-232. doi: 10.11781/sysydz202102227

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Coal seams of the Longtan Formation in the Zhijin area of Guizhou province present the characteristics of multiple layers and small individual thickness. Compared with single thick-layered coal seam, multiple coal seams have differences in reservoir pressure gradient, formation liquid supply capacity, permeability and desorption pressure, which affect the efficiency of combined mining and the degree of resource utilization. In order to enahance the production potential of coalbed methane and improve the economics, it is valuable to optimize commingled production and establish a multi-seam development sequence. In view of these problems, this paper carried out a study on the differences of geological conditions of multiple coal seams. Combined with drainage practice and desorption theory, the influencing factors of multi-layer commingled production in the Zhijin area were discussed, and the production strategy was optimized. The results showed that desorption liquid level height, longitudinal span, pressure gradient, liquid supply capacity and permeability difference are the key factors affecting multi-layer commingled production. The main coal seams in the Upper Permian Longtan Formation in the study area have small differences in liquid supply capacity, pressure gradient and permeability, hence these have less impact on commingled production. The differences in longitudinal span and desorption liquid level height are the key factors affecting commingled production in the study area. A 90 m span can be used as a development combination for coal seams no. 16/17/20/23/27/30. A practice in large well group obtained a stable production of 2 000 m³/d, proving that commingled production is viable.

Formation conditions of shale oil and favorable targets in the second member of Paleogene Funing Formation in Qintong Sag, Subei Basin

ZAN Lin, LUO Weifeng, YIN Yanling, JING Xiaoming

2021, 43(2): 233-241. doi: 10.11781/sysydz202102233

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The favorable targets of shale oil exploration were optimized based on the analyses of hydrocarbon generation, reservoir conditions and oil content of the shale sections in the second member of Paleogene Funing Formation in the Qintong Sag, Subei Basin. Some favorable zones were predicted according to the properties of lithology, pressure and fractures. The mud shale with an organic carbon content (TOC) greater than 1.0% is widespread in the second member of Funing Formation with the thickness distributed between 160-260 m. The R_o values vary from 0.5% to 1.1%, indicating a wide maturity range. The organic matter type is good, and the organic microscopic maceral is dominated with algae, which provides a substantial potential for generation of shale oil. The average porosity of the second member of Funing Formation is 8.9%. Dissolved pores, clay minerals and carbonate intercrystalline pores act as main reservoir spaces. For the laminar marls and silty mudstones, micro-fractures were well developed, which controlled the permeability of the reservoir. From the third to the fifth section of the second member of Funing Formation, the content of brittle minerals distributed between 62%-65%, mainly composed with quartz, calcite and dolomite. The free hydrocarbon content (S₁) showed a range of 0.1-2.7 mg/g, with an average value of 0.54 mg/g, referring the most favorable layers for shale oil exploration of the sections mentioned above. The shale oil in the second member of Funing Formation in the study area was mainly types Ⅱ and Ⅲ. It has also been indicated that the Shiyan and Chujialou deep depressions are the most favorable areas for silty mudstone and marl reservoirs, while the eastern slope is favorable for tuff mudstone shale reservoirs.

Macro-heterogeneity evaluation based on different sand body structures: a case study of Chang 8 reservoir group in Heshui area, Ordos Basin

CHEN Zhaobing, FU Ling, NAN Fanchi, RAN Jing, CHEN Xinjing, ZONG Chaolun, LI Haoyuan

2021, 43(2): 242-249. doi: 10.11781/sysydz202102242

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Macro-heterogeneity is one of the important factors affecting oilfield development, especially for deltaic sedimentary environments with complex sand body structures. The structure type and characteristics of sand bodies were analyzed for Chang 8 reservoir group (the eighth member of Upper Triassic Yanchang Formation) in the Heshui area of the Ordos Basin. An evaluation method for reservoir macro-heterogeneity was established based on outcrop and core observation, and logging and production performance data. Four sand body structures in the Chang 8 shallow water delta were identified, including continuous superposition, interval superposition, lateral single layer and sand-mud interbedded types. The interlayers and restraining barriers lead to the decrease of the spatial continuity of sand body. Generally, the development degree of interlayers and permeability heterogeneity of the continuous superimposed type is the weakest, and the macro-heterogeneity is the weakest, followed by the interval superposition and the lateral single layer types, while the macro-heterogeneity of sand-mud interbedding type is the strongest. The interlayer density (D_K), interlayer frequency (P_k) and reservoir quality coefficient (R_QI) were selected to construct the evaluation index (N) of intraformational heterogeneity. The N index can reflect the fluid displacement characteristics and water content change of single sand body within different sand body structures. The evaluation index J of interlayer heterogeneity was constructed by selecting parameters such as the percentage of sandstone (S_n) and the number of interlayer sand layers per unit thickness (T). The J index is a good measure to evaluate and predict the fluid production strength of oil wells. Therefore, the intraformational heterogeneity index (N) and interlayer heterogeneity index (J) can be used to evaluate the macro-heterogeneity of reservoirs.

Characteristics of in situ stress of tight oil reservoirs and its influence on petrophysical properties: a case study of Upper Triassic Yanchang Formation in Ordos Basin

GAO Yi, LIN Lifei, YIN Shuai, HU Guoxiang, MA Rongli

2021, 43(2): 250-258. doi: 10.11781/sysydz202102250

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The petrophysical properties of tight reservoirs and the state of fluid occurrence are affected by current geostress. In the past, there were few studies on the rock mechanical properties and in situ stress of the Yanchang Formation in the central and western regions of the Ordos Basin, which restricted the efficient exploration and development of tight oil and gas. A systematic study was carried out on the rock mechanical properties, in situ stress characteristics and their effects on the petrophysical properties of the Chang 6-Chang 8 reservoirs in the Wuqi, Zhidan and Dingbian areas in the Ordos Basin. A reliable method of in situ stress logging interpretation using fracturing methods and logging models was established. The Chang 6 to Chang 8 in Wuqi area is not significantly stressed. The horizontal stress activity deep in the Zhidan area is greater than that in the shallow layers, with the strong horizontal stress intensity mainly concentrated in Chang 7₃ and Chang 8. The horizontal stress activity of the Dingbian area is relatively strong from Chang 6 to Chang 8, and the horizontal stress intensity of the shallow layer is slightly stronger than that of the deep layer. The stress gradients in the three work areas are determined. The horizontal principal stress gradient gradually increases from northwest to southeast. Finally, the influence of horizontal compression stress on the path of rock compaction and the petrophysical properties of the reservoir are systematically discussed. It was found that the increase of σ_H-σ_h did not cause the loss of rock pores alone. The stress plane heterogeneity will cause three different paths of rock porosity changes. However, the increase of the horizontal principal stress difference will mainly cause a decrease of rock permeability.

Accumulation factor matching and model of Bozhong 19-6 buried hill gas reservoir, Bohai Sea area

NIU Chengmin, WANG Feilong, HE Jiangqi, TANG Guomin

2021, 43(2): 259-267. doi: 10.11781/sysydz202102259

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The accumulation factors and mechanism of the 100 billion cubic meters gas reservoir in the Bozhong 19-6 buried hill of the Bohai Sea area were studied using geochemical analyses and basin modelling based on a large amount of core, cast thin section, well logging and geochemical data. The results showed the following. (1) The gas generated by the source rocks of the third member of the Shahejie Formation in the Bozhong Sag generally exceeds 5×10⁹ m³/km². The continuous hydrocarbon supply in the late period provided sufficient material for the formation of the Bozhong 19-6 buried hill gas reservoir. (2) The Indosinian and Yanshanian tectonic movements were the key periods for the formation of structural fractured reservoirs and buried-hill traps, and formed a near-source fault transport system and a far-source unconformity transport system. (3) The thick overpressure mudstone cap rocks of the Dongying Formation and the weak tectonic activity in the late period were beneficial to the preservation of the Bozhong 19-6 buried hill gas reservoir. (4) The time-space matching of the six major accumulation factors of "generation, storage, cap rock, trap, migration, and preservation" ultimately led to the formation of a large gas field of 100 billion cubic meters in the Bozhong 19-6 buried hill. A late accumulation model of multi-depression hydrocarbon supply, multi-directional charging, combined fault and unconformity transport was established in the Bozhong 19-6 buried hill.

Characteristics of reservoirs for inter-salt shale oil of Qianjiang Formation, Qianjiang Sag, Jianghan Basin: a case study of the Eq₃⁴-10 rhythm

LIU Xinrui, WU Shiqiang, CHEN Fengling, ZHANG Liang, DU Xiaojuan, GUAN Wenjing, LIANG Wenchuan

2021, 43(2): 268-275. doi: 10.11781/sysydz202102268

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The inter-salt shale oil of the Eocene Qianjiang Formation in the Jianghan Basin is a hot and difficult research target in recent years. In order to clarify the lithofacies and physical properties of the inter-salt shale reservoirs, based on core observation, thin section observation, X-ray diffraction, high-pressure mercury intrusion and shale porosity and permeability analyses, a case study was carried out for the Qianjiang Formation in the Qianjiang Sag of Jianghan Basin. Results showed that there were three types of lithofacies, including carbonaceous laminar argillaceous dolomites, carbonaceous lamellar dolomitic/lime mudstones and carbonaceous lamellar dolomitic mudstones filled with glauberites. The porosities of the first two lithofacies were significantly higher than that of the latter. The pore size distribution of different lithofacies showed that the carbonaceous laminar argillaceous dolomites were dominated by pores with radius greater than 41 nm, and the median pore-throat radius was 219 nm, while the other two facies were dominated by pores with pore radius less than 41 nm and the median pore-throat radius was 21 nm. The carbonaceous laminar argillaceous dolomites were indicated to be homogeneous in lithology. As reservoir, they have good reservoir space, larger pore-throat structure and higher oil content, and was the dominant facies in the inter-salt shale oil reservoir and is promising to be the most favorable shale oil exploration target in the study area.

Geological significance of late Mid-Permian stratigraphy in northern and eastern Sichuan Basin, SW China

YAO Qianying, LIU Yifeng, JIANG Qingchun, HAO Yi, LI Jingrui, LÜ Xueju, SU Wang, FU Xiaodong

2021, 43(2): 276-287. doi: 10.11781/sysydz202102276

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The Mid-Permian Maokou Formation in the Sichuan Basin shows good petroleum prospectivity. However, knowledge of the stratigraphy in the northern and eastern Sichuan Basin during the late Maokou period are still unclear. The interface between the Maokou and Wujiaping formations was re-identified, and the sedimentary pattern in the study area during the late Maokou period was clarified based on the logging data from 120 wells combined with the measured data of three field profiles. The results suggest the following. (1) Natural gamma-ray spectral logging can effectively identify the siliceous sediments at the top of Maokou Formation and the mud shale at the bottom of Wujiaping Formation. According to a new stratigraphic division, the erosional edge on LHST2 section of Maokou Formation moved eastward to the Kaixian area. (2) Tectonic subsidence controlled the eastward thinning and the sedimentary evolution in the late Maokou period. (3) The sedimentary evolution in the late Maokou period was from the homoclinal carbonate ramp facies to the distal steepening ramp facies, and then to the weak rimmed platform facies. Distal steepening ramp facies controlled the formation of dolomite and siliceous sediments, while the weak rimmed platform facies controlled the formation of the platform margin.

Normal fault evolution in Lishu Fault Depression, southern Songliao Basin

DENG Mingzhe, ZUO Zongxin, QIU Qi, BAI Fan

2021, 43(2): 288-296. doi: 10.11781/sysydz202102288

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The formation of the Songliao Basin was affected by multidirectional tectonic stress and various peripheral structural belts, and has a complicated geological structure and basin evolution process. The Lishu Fault Depression in the southern Songliao Basin has the characteristics of superimposed and complex evolution of multiple tectonic activities, and is a good window to reveal the impacts of the peripheral structural belts and basin tectonic-sedimentary response. Whether strike-slip tectonic activity controls the sedimentary process of the basin is an unsolved problem. Using three-dimensional seismic data to carry out detailed interpretation, combined with fault distance statistics, structural model analysis and other research methods, the extension activities of the Sangshutai and Qinjiatun faults in the Lishu Fault Depression during the Early Cretaceous were studied. The evolution process of the Sangshutai fault was controlled by the nearly east-west extensional tectonic stress. The initial scale of the fault was large, so the Sangshutai fault was less affected by the adjustment of the extension direction. The Qinjiatun fault was controlled by the NEE-SWW extension during the Early Cretaceous Huoshiling period, and by the NE-SW extension during the Early Cretaceous Shahezi period. The regional strike-slip activity in the Early Cretaceous extension in the Lishu Fault Depression caused a change in the extension direction.

Thermal evolution history reconstruction of Carboniferous source rocks on the northeastern margin of Junggar Basin using TSM basin simulation technology

ZHOU Yushuang, JIA Cunshan, ZHANG Kuihua, ZHAO Yongqiang, YU Qixiang, JIANG Xingge, CAO Qian

2021, 43(2): 297-306. doi: 10.11781/sysydz202102297

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Multiple sets of source rocks developed in the Carboniferous on the northeastern margin of Junggar Basin. Modelling the thermal evolution history of source rocks is of great importance to deepen the understanding of hydrocarbon accumulation. Based on the study of basin evolution and source rock development characteristics, this paper applies a TSM Basin Simulation and Resource Evaluation System to establish one-dimensional and three-dimensional basin simulation models so as to reconstruct the burial, thermal evolution and hydrocarbon generation histories of different structural units. There are obvious differences in the hydrocarbon generation and evolution process of Carboniferous source rocks in different sags on the northeastern margin of the Junggar Basin. The Carboniferous source rocks in the Wulungu Depression entered the low-maturity evolution stage at the end of the Carboniferous, stagnated due to uplifts in the Permian, reached the threshold of secondary hydrocarbon generation at the end of Triassic when burial resumed, and are now in the over-mature stage, mainly generating dry gas (R_o>2.0%). The Carboniferous source rocks in the Sannan Sag entered the low-maturity stage in the Permian and are now in the high-maturity gas-producing stage (R_o=1.5%-1.9%). The Carboniferous source rocks in the Dishuiquan Sag entered the low-maturity stage in the Triassic and are now in the mature oil-producing stage (R_o=0.8%-1.3%). Simulation calculations show that the cumulative hydrocarbon generation of the source rocks in the Carboniferous Jiangbasitao Formation in the Wulungu Depression amounts to 20.5×10⁹ t, in which the cumulative hydrocarbon generation until the end of Carboniferous is 10.3×10⁹ t, which is the main oil generation stage. The cumulative gas generation at the end of Cretaceous is 18.4×10⁹ t, which is the main gas generation period.

Evaluation of geochemical characteristics and source of natural gas in Lower Paleozoic, Daniudi area, Ordos Basin

SUN Xiao, WANG Jie, TAO Cheng, ZHANG Yi, JIA Huichong, JIANG Haijian, MA Liangbang, WANG Fubin

2021, 43(2): 307-314. doi: 10.11781/sysydz202102307

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In recent years, great progress has been made in the exploration of natural gas in the Paleozoic in the Daniudi Gas Field in the northern Ordos Basin, especially the discovery of high yield industrial gas flow in the Ordovician weathering crust. However, the study of the origin and source of natural gas in the Lower Paleozoic in the Daniudi area is relatively limited, which directly restricts the next exploration project in the Lower Paleozoic in the northern Ordos Basin. The systematic analyses of gas components and carbon, hydrogen and noble gas isotopes showed that natural gas of the Paleozoic in the Daniudi area is dominated by methane and contains a certain amount of heavy hydrocarbons, and the carbon dioxide and nitrogen content is relatively high. It is not only dry gas generated at high to over maturity, but also wet gas originated from the mature stage. The natural gas of the Upper Paleozoic in the Daniudi area is a typical coal-type gas, while the natural gas of the Lower Paleozoic is both coal-type gas and oil-type gas. The carbon dioxide in the natural gas of the Paleozoic is mainly organic and with a small amount in the Lower Paleozoic being inorganic, which may be produced by the pyrolysis of carbonate minerals in the Lower Paleozoic source rocks. Geochemical analyses such as the carbon isotopes of source rock desorption gas, natural gas and kerogen, the hydrogen isotope of methane, the argon isotope dating, and the end-member gas mixed simulation experiments demonstrated that the coal-type gas in Upper and Lower Paleozoic in the Daniudi area in the northern Ordos Basin originated from the Upper Paleozoic coal-bearing source rocks, while the oil-type gas in the Lower Paleozoic was mixed with 0-45% coal-type gas, and the oil-type gas was predominant in the natural gas, which mainly originated from the source rocks of the Majiagou Formation in the Lower Paleozoic.

Origin and mixing ratio of crude oils in different charging episodes of Yangjiang Sag of Pearl River Mouth Basin

XIONG Wanlin, LONG Zulie, ZHU Junzhang, YANG Xingye, FENG Yong

2021, 43(2): 315-324. doi: 10.11781/sysydz202102315

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The oil and gas exploration in the Yangjiang Sag of Pearl River Mouth Basin has successfully carried out and breakthroughs have been achieved in the past two years. The generation mechanisms of crude oils of multiple charging episodes were studied and the sources, mixing ratios were quantitatively calculated by the using of analytical results of gas chromatography-mass spectrometry (GC-MS) for the saturated hydrocarbon fractions, fluid inclusion system analysis and whole-oil gas chromatography (GC-FID) for mixed-source oil proportion experiment. Results showed that there were two episodes of crude oil charging in the Yangjiang Sag, 12.0-7.5 Ma and 6.5-0 Ma. In the first stage, crude oils came from the medium-shallow deposited lacustrine source rocks in the third member of Wenchang Formation in the Enping 20 sub-sag, and mainly were accumulated in the Zhujiang Formation. In the second stage, crude oil came from the medium-deep deposited lacustrine source rocks of the first and second members of Wenchang Formation, and accumulated in the Zhujiang and Hanjiang formations. A template for the calculation of mixed propotion of oils was established through quantitative experiments. It was concluded that the Hanjiang reservoirs in the B20-1 and B20-2 oil fields were mainly charged during the second episode, while the Zhujiang reservoirs in the B20-1 oil field were charged during both the first and the second episodes, accounting for 39% and 61%, respectively. The coupling relationship among fault activity intensity, trap development interval and effective source rock controlled the degree of enrichment.

Recent progress in the theory and technology of microbial prospecting for oil and gas

TANG Yuping, XU Kewei, GU Lei, YANG Fan, GAO Junyang, REN Chun, WANG Guojian

2021, 43(2): 325-334. doi: 10.11781/sysydz202102325

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Microbial prospecting for oil and gas (MPOG) is a surface exploration technology derived from the principle of light hydrocarbon micro-seepage from oil and gas reservoirs. The light hydrocarbons (C₁-C₅) in oil and gas reservoirs permeate the overlying sedimentary layer in the way of micro-seepage, which induces the growth of microorganisms specializing in the consumption of light hydrocarbons in near-surface soil. As a result, the microbial concentration and community structure in oil and gas areas will be different from that without underlying oil and gas reservoirs. By analyzing the abnormal characteristics of microbial concentration and community structure, the oil and gas enrichment areas and oil and gas reservoirs are predicted. In recent years, the research team has established sample acquisition and pretreatment techniques for different geomorphology and surface types, and combined with traditional culturing and molecular biology methods, the precise diagnosis of oil and gas from the perspective of both hydrocarbon indication microorganism quantity and community structure is realized. The artificial simulation results lasting three years show that there are obvious differences and responsive relationships between the microorganisms and community structure under the acclimation of different hydrocarbon components. The strains found are consistent with the actual oil and gas reservoir, providing a theory basis for microbial exploration. In addition, the correlation among environmental conditions, hydrocarbon geochemistry and hydrocarbon microbial group distribution was studied using different oil and gas reservoir types and different geographical conditions. The rule of microbial community in situ of oil and gas reservoir samples was analyzed, and a database of oil and gas indicators in typical oil and gas basins in China was preliminarily constructed. The results showed that the surface microbial anomaly was closely related to the location of oil and gas reservoirs, and can reflectthe characteristics of oil and gas reservoirs of different types. Combined with petroleum geology and geophysical data, the microbial exploration technology can effectively predict the favorable enrichment areas of oil and gas. This paper also presents nine development trends of MPOG.

Accurate evaluation of source rocks in source-reservoir integration: a case study of source rocks in Lucaogou Formation, Jimsar Sag, Junggar Basin

LI Erting, WANG Jian, LI Ji, HE Dan, GAO Xiuwei, LIU Cuimin, WANG Haijing

2021, 43(2): 335-342. doi: 10.11781/sysydz202102335

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In the Middle Permian Lucaogou Formation in the Jimsar Sag of Junggar Basin, source rocks and reservoirs are integrated. Crude oil impregnation is very common in core samples, which leads to the inaccurate determination of source rock evaluation parameters. The impact of migrated hydrocarbon on source rock evaluation was analyzed using chloroform extraction. The hydrocarbon potential of source rocks which were integrated with reservoirs in the Lucaogou Formation was evaluated accurately in view of different lithologies. The higher the content of soluble hydrocarbons in the source rock, the higher the deviation of the measured value of the source rock's total organic carbon, the higher the pyrolysis parameters S₁ and S₂, the lower the T_max value, and the higher the hydrogen index. For source rocks integrated with reservoirs, chloroform extraction should be performed first, followed by pyrolysis analysis. For the Lucaogou source rocks in the study area, mudstones have the highest abundance of organic matter and comprise the best source rocks, followed by dolomites, which are good source rocks. Limestones are medium-good source rocks, while siltstones are mainly poor source rocks. The organic matter types of source rocks are mainly type Ⅰ, type Ⅱ₁, and type Ⅱ₂, with a small amount of type Ⅲ, which has reached the mature oil production stage. The organic carbon content, hydrogen index, and T_max value of extracted source rocks can be effectively used for the accurate evaluation of the source rocks integrated with reservoirs or impregnated with oil.

Mechanical properties and influencing factors of Funing Formation sandstone reservoir in Jinhu Sag, Subei Basin

SUN Ke, CHEN Qinghua

2021, 43(2): 343-353. doi: 10.11781/sysydz202102343

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Reservoir rock mechanics plays a key role in oil and gas field development. The relationship between lithology, temperature, fluid and confining pressure and the mechanical properties of sandstone reservoirs and the influence mechanism of each factor were discussed using rock mechanics tests, X-ray diffraction, cast thin section and scanning electron microscopy analyses of core samples from the Funing Formation in the Jinhu Sag of Subei Basin. Lithology is a decisive factor for the mechanical properties of sandstones, which are related to particle size, quartz content, clay mineral content, particle contact and cement content. The influence of temperature on the mechanical properties of sandstones is segmented. At 25-100 ℃, minerals expand and contract, while interlayer water escapes. At 100-180 ℃, thermal cracking is dominant. As the oil-water ratio decreases, the mechanical parameters of sandstones change regularly, and the weakening of sandstone strength is related to pore fluid pressure, partial saturation and chemical effects. Artificial measures in oilfield development have a significant impact on the mechanical properties of sandstone reservoirs, and attention should be paid on sand production prediction and wellbore stability analysis.

Geophysical methods for quantitative resumption of paleo-structures and its application

JING Keyao, CHEN Xia, JIN Xiaohui

2021, 43(2): 354-359. doi: 10.11781/sysydz202102354

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Paleo-structures can be resumed and the fine studies of tectonic evolution can be achieved using bedding flattening technique and paleo-stratigraphic thickness calculation based on the interpretation of seismic data. The synthetic records of stratigraphic and seismic refection characteristics of multiple wells were made so as to accurately calibrate the reflection wave group of the main target layer. The tectonic profiles of different layers were studied using bedding flattening technique. The three-dimensional seismic interpretation data of the bottom and top of the target layer was used to restore the paleo-structural morphology of the key sedimentary period, and to perform a three-dimensional display. In this way, the characteristics of structural changes in the key sedimentary period were finely depicted on the plane. The paleo-structural characteristics of the Zhenjing area in the Ordos Basin recovered by this technique reasonably explain the present law of oil and gas distribution. Before the deposition of the Jurassic, several nose-like uplifts had developed in this area, and the subsequent stratigraphic deposits have a certain degree of inheritance. The source rocks of the Upper Triassic Yanchang Formation entered the hydrocarbon generation threshold after experiencing thermal events during the late Middle Jurassic and began to expel hydrocarbons. Oil generation peak occurred in the middle and late periods of the Early Cretaceous, and some favorable hydrocarbon accumulation areas were formed. The oil produced by the main source rocks under the pressurization of hydrocarbon generation migrated into the channel sandstones of the Chang 8¹ and Chang 9 oil groups nearby, forming self-generating, self-storing and self-capped oil reservoirs. The understanding of the oil and gas distribution law in this area provides a technical support for the further optimization of favorable traps.

Ar-ion polishing FE-SEM analysis of organic maceral identification

GAO Fenglin, WANG Chengxi, SONG Yan, CHEN Zhenhong, LIU Qingxin, LI Zhuo, JIANG Zhenxue, ZHANG Xinxin

2021, 43(2): 360-367. doi: 10.11781/sysydz202102360

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Abstract:
Argon-ion polishing field emission-scanning electron microscopy (FE-SEM) is a common method to characterize the microscopic pore structure characteristics of shale reservoirs, but organic macerals cannot be directly identified by FE-SEM alone. Fluorescence microscopy is the main method for identifying macerals. Through a large number of localized FE-SEM and fluorescence microscopy observations, the microscopic characteristics of specific macerals under FE-SEM were summarized. The macerals visualized using FE-SEM can be interpreted based on features such as the external shape, hardness, brightness, color, relief, organic pore development characteristics and fissure development characteristics of the organic matter. Telinite, collotelinite, vitrodetrinite, fusinite, semifusinite, funginite, inertodetrinite, oil bitumen and pyrobitumen were identified.

Constant velocity mercury injection and nuclear magnetic resonance in evaluation of tight sandstone reservoirs in western Sichuan Basin

FENG Dongjun, XIAO Kaihua

2021, 43(2): 368-376. doi: 10.11781/sysydz202102368

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Abstract:
The reservoir porosity, pore structure type, pore-throat characteristics, pore-throat ratio and their correlations with porosity and permeability of the fourth member of Upper Triassic Xujiahe Formation in the Xinchang area of the western Sichuan Basin were discussed based on constant velocity mercury injection and nuclear magnetic resonance. The effects of pores and throats on capillary curves were studied, and the influence of pore throat characteristics on movable fluid parameters was discussed. The reservoir of the fourth member of Xujiahe Formation in the study area has low porosity and low to ultra-low permeability. Its porosity ranges from 1.6% to 10.9%, with an average of 5.9%, and the permeability ranges from 0.01×10^-3 μm² to 2.81×10^-3 μm², with an average of 0.37×10^-3 μm². There are four types of pore structures: coarse throat and macro pore, coarse throat and small pore, fine throat and macro pore, and fine throat and small pore. The pore radius is 8-180 μm, with an average of 112 μm, mainly micropores and small pores. The throat radius ranges from 0.100 to 1.008 μm, with an average of 0.484 μm, mainly microthroats. Pore radius has little influence on the physical properties of low to ultra-low permeability reservoirs. Pore throat radius has a good correlation with permeability, which determines the variation characteristics of capillary curves and controls the physical properties of low permeability reservoirs, and is the key factor to determine the development effect of gas reservoirs. The experimental parameters, such as pore radius, throat radius and final mercury saturation, which have great influence on movable fluid parameters, were optimized. A pore structure index was put forward based on the three parameters mentioned above, and the reservoir evaluation of the whole well section was carried out, which was applied to the evaluation of tight sand reservoirs in the western Sichuan Basin.

2021, 43(2): 377-377.

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Abstract:

2021 Vol. 43, No. 2

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