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Research progress on casing deformation types and influencing factors in geological engineering of shale gas wells
YAN Jianping, LAI Siyu, GUO Wei, SHI Xuewen, LIAO Maojie, TANG Hongming, HU Qinhong, HUANG Yi
2024, Vol.36(5): 1–14
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Pore structure characteristics and dehydration evolution of lignite reservoirs of Jurassic Xishanyao Formation in Santanghu Basin
KONG Lingfeng, XU Jiafang, LIU Ding
2024, Vol.36(5): 15–24
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Sedimentary filling process and petroleum geological significance of Cambrian Canglangpu Formation in Sichuan Basin and adjacent areas
ZHOU Gang, YANG Dailin, SUN Yiting, YAN Wei, ZHANG Ya, WEN Huaguo, HE Yuan, LIU Sibing
2024, Vol.36(5): 25–34
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186 )
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271
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Prediction and main controlling factors of tuff reservoirs of Cretaceous Huoshiling Formation in Dehui fault depression，Songliao Basin
WANG Hongxing, HAN Shiwen, HU Jia, PAN Zhihao
2024, Vol.36(5): 35–45
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Oil and gas migration characteristics of lithologic reservoirs of Neogene Minghuazhen Formation in Bozhong A-2 area，Bozhong Sag
CHENG Yan, WANG Bo, ZHANG Tongyao, QI Yumin, YANG Jilei, HAO Peng, LI Kuo, WANG Xiaodong
2024, Vol.36(5): 46–55
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Provenance transformation and sedimentary filling response of Mesozoic in Halahatang-Hade area，Tarim Basin
YI Zhenli, SHI Fang, YIN Taiju, LI Bin, LI Meng, LIU Liu, WANG Zhukun, YU Ye
2024, Vol.36(5): 56–66
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141 )
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(14336 KB)
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129
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Characteristics of multi-phase thermal fluid activity and natural gas migration-accumulation of Cenozoic in No. 2 fault zone of Qiongdongnan Basin
HUANG Xiangsheng, YAN Zhuoyu, ZHANG Dongfeng, HUANG Heting, LUO Chengfei
2024, Vol.36(5): 67–76
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87 )
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146
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Simulation and prediction of tight sandstone reservoirs based on waveform facies-controlled inversion：A case study from the second member of Paleogene Kongdian Formation in southern Cangdong sag， Huanghua Depression
ZHOU Ziqiang, ZHU Zhengping, PAN Renfang, DONG Yu, JIN Jineng
2024, Vol.36(5): 77–86
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Reservoir characteristics and main controlling factors of Jurassic Shaximiao Formation in Wubaochang area，northeastern Sichuan Basin
ZHANG Xiaoli, WANG Xiaojuan, ZHANG Hang, CHEN Qin, GUAN Xu, ZHAO Zhengwang, WANG Changyong, TAN Yaojie
2024, Vol.36(5): 87–98
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126 )
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(12441 KB)
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158
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Main controlling factors of shale gas enrichment of Ordovician Wufeng Formation-Silurian Longmaxi Formation in Ningxi area，Sichuan Basin
YANG Xuefeng, ZHAO Shengxian, LIU Yong, LIU Shaojun, XIA Ziqiang, XU Fei, FAN Cunhui, LI Yutong
2024, Vol.36(5): 99–110
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110 )
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171
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Lithofacies classification of tight sandstone based on Bayesian Facies-AVO attributes：A case study of the first member of Jurassic Shaximiao Formation in central Sichuan Basin
CHEN Kang, DAI Juncheng, WEI Wei, LIU Weifang, YAN Yuanyuan, XI Cheng, LYU Yan, YANG Guangguang
2024, Vol.36(5): 111–121
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138 )
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Structural characteristics and hydrocarbon accumulation model of Cambrian Xixiangchi Formation in eastern Sichuan Basin
QIU Yuchao, LI Yading, WEN Long, LUO Bing, YAO Jun, XU Qiang, WEN Huaguo, TAN Xiucheng
2024, Vol.36(5): 122–132
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Characteristics and reservoir control of source rocks of Triassic Chang 7 member in Qingcheng area，Ordos Basin
WANG Zixin, LIU Guangdi, YUAN Guangjie, YANG Henglin, FU Li, WANG Yuan, CHEN Gang, ZHANG Heng
2024, Vol.36(5): 133–144
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Characteristics of deep-water deposits and evolution law of Triassic Chang 7 reservoir in southeastern Ordos Basin
YIN Hu, QU Hongjun, SUN Xiaohan, YANG Bo, ZHANG Leigang, ZHU Rongxing
2024, Vol.36(5): 145–155
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Characteristics of source rocks and thermal evolution simulation of Permian Pingdiquan Formation in Dongdaohaizi Sag，Junggar Basin
YANG Haibo, FENG Dehao, YANG Xiaoyi, GUO Wenjian, HAN Yang, SU Jiajia, YANG Huang, LIU Chenglin
2024, Vol.36(5): 156–166
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Formation mechanism and evolution characteristics of overpressure in deep Permian in eastern Fukang Sag，Junggar Basin
WEI Chenglin, ZHANG Fengqi, JIANG Qingchun, LU Xuesong, LIU Gang, WEI Yanzhao, LI Shubo, JIANG Wenlong
2024, Vol.36(5): 167–177
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Natural depletion characteristics and pressure maintenance strategies of faultcontrolled fracture-cavity condensate gas reservoirs in Shunbei Oilfield
SU Hao, GUO Yandong, CAO Liying, YU Chen, CUI Shuyue, LU Ting, ZHANG Yun, LI Junchao
2024, Vol.36(5): 178–188
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Research progress on casing deformation types and influencing factors in geological engineering of shale gas wells
YAN Jianping, LAI Siyu, GUO Wei, SHI Xuewen, LIAO Maojie, TANG Hongming, HU Qinhong, HUANG Yi
2024, Vol.36(5): 1–14
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doi: https://doi.org/10.12108/yxyqc.20240501
By investigating a large number of domestic and foreign literatures on casing deformation in shale gas wells，the types of casing deformation in shale gas wells were summarized，the differences and problems of influencing factors of casing deformation in deep and shallow shale gas wells were discussed，and the corresponding prevention measures and the main research directions in the next step were put forward. The results show that：（1）The types of casing deformation in shale gas wells mainly include squeezing diameter deformation and shear deformation. The probability of casing deformation in deep shale gas wells is greater than that in middle and shallow layers，and is mainly shear deformation.（2）The engineering factors that cause casing deformation include wellbore cooling，cementing quality，casing fatigue，casing quality and wellbore dogleg degree. The geological factors include rock mechanical properties，non-uniform in-situ stress stress and natural fracture/fault slip. The casing deformation of deep shale gas wells is mainly affected by natural fracture/fault slip.（3）Measures can be taken to reduce the risk of casing deformation，such as controlling wellbore temperature and injection strength，using cement with lower mechanical properties of cement sheath for cementing operation，appropriately reducing the outer diameter of casing，increasing wall thickness，improving steel grade，to improve casing quality，and smoothing well trajectory as far as possible. For deep shale gas wells，the risk of casing shear deformation can also be reduced by designing the extension direction of the horizontal section of the wellbore to be consistent with the bedding direction of the rock formation，mastering the fracture distribution，avoiding the high-risk shear slip section as much as possible，reasonably reducing the fracturing scale for different levels of slip risk sections，and adjusting the wellbore orientation.（4）The research directions of casing deformation prevention and control of shale gas wells mainly include four aspects：optimizing fracturing layers with good rock mechanical properties，analyzing the relationship between optimal well trajectory and in-situ stress，identifying and evaluating fractures，calculating fault slip and casing variables.
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Pore structure characteristics and dehydration evolution of lignite reservoirs of Jurassic Xishanyao Formation in Santanghu Basin
KONG Lingfeng, XU Jiafang, LIU Ding
2024, Vol.36(5): 15–24
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doi: https://doi.org/10.12108/yxyqc.20240502
It is helpful to accurately predict the operation effect of underground coal gasifier to find out the difference and evolution law of pore structure of coal before and after drying. By selecting water and kerosene as saturated fluids to carry out low-field NMR experiment，the pore structure of the same sample under saturated and dry conditions was tested and compared. The dehydration evolution process of pore structure of coal samples was observed through X-CT technology and an evolution model was established，and pulse attenuation permeability test and low-temperature liquid nitrogen adsorption experiments were conducted to evaluate the mass transfer ability of coal samples. The results show that：（1）During the drying of lignite，pore shrinkage occurs while cracks are produced，and the total pore volume decreases from 0.630 cm3/g to 0.481 cm3/g，while the large pore volume significantly increases from 0.070 cm3/g to 0.420 cm3/g. Dehydration leads to pore concentration，with the large pore volume accounting for 88%.（2）The pore shrinkage during the drying of lignite is controlled by the degree of matrix shrinkage. The dehydration of different coal rock components can be summarized into two types of pore structure evolution models：the dehydration of matrix coal that is prone to shrink develops a large number of cracks at the edges or inside of the components，while the dehydration shrinkage of xylite-rich and charcoal-rich coal is weak，retaining a large number of primary pores and developing fewer cracks.（3）After the drying of the lignite，water is removed and the number of empty pores increases. The seepage state changes from single-phase water to gas-water two-phase and single-phase airflow，forming a good interconnected pore network. The seepage ability of the coal is significantly improved，and the permeability increases from 0.248 to 48.080 mD. The contribution of diffusive mass transfer is increased，with diffusion coefficient of medium and large pores in dry lignite being about 0.09 cm2/s at a temperature of 200 ℃ and a pressure of 0.5 MPa.
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Sedimentary filling process and petroleum geological significance of Cambrian Canglangpu Formation in Sichuan Basin and adjacent areas
ZHOU Gang, YANG Dailin, SUN Yiting, YAN Wei, ZHANG Ya, WEN Huaguo, HE Yuan, LIU Sibing
2024, Vol.36(5): 25–34
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doi: https://doi.org/10.12108/yxyqc.20240503
Based on outcrops，drilling cores，logging and seismic data，the sedimentary filling process of Cambrian Canglangpu Formation in Sichuan Basin and adjacent areas were studied. The results show that：（1）The overall sedimentary structural pattern of the first member of Cambrian Canglangpu Formation（Cang-1 member） in Sichuan Basin presents “one uplift，four depressions，and two high zones” characteristics，with carbonate rocks as the main lithology. The second member of Canglangpu Formation（Cang-2 member）is gradually filled in，and the regional paleogeomorphology tend to be uniform，with clastic rocks being the main lithology. （2）During the sedimentary period of Cang-1 member in the study area，the barrier effects of Deyang-Anyue ancient rift trough led to an east-west differentiation sedimentary pattern in the plane. The western trough which is near the provenance，mainly developed mixed tidal flat deposits，while the eastern trough mainly developed carbonate deposits. During the sedimentary period of Cang-2 member，the barrier effects of trough was weakened，and the terrigenous debris significantly increased in the whole basin that were characterized by clastic rock shallow shelf deposits.（3）The high-quality dolomite reservoirs of Cang-1 member in the study area are mainly composed of residual oolitic dolomite，sandstone dolomite，and powder crystal dolomite. Macroscopically，the distribution of shoals is mainly controlled by underwater low uplift and relatively high parts of the platform depression edge. Microscopically，the reservoir space is mainly controlled by dolomitization and dissolution transformation，with intragranular dissolved pores，intergranular dissolved pores，and intercrystalline dissolved pores developed. It is adjacent to the high-quality source rocks of the underlying Qiongzhusi Formation and has an advantage of near-source filling and accumulation.
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Prediction and main controlling factors of tuff reservoirs of Cretaceous Huoshiling Formation in Dehui fault depression，Songliao Basin
WANG Hongxing, HAN Shiwen, HU Jia, PAN Zhihao
2024, Vol.36(5): 35–45
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doi: https://doi.org/10.12108/yxyqc.20240504
Based on the core analysis，data of well logs and seismic，the distribution characteristics and oil-gas enrichment conditions of tuff reservoirs of Cretaceous Huoshiling Formation in Dehui fault depression of Songliao Basin were analyzed by using forward modelling and multi-parameter inversion body fusion technology， and the distribution of high-quality reservoirs was predicted. The results show that：（1）The tuff of Cretaceous Huoshiling Formation in Dehui fault depression，Songliao Basin，is a pyroclastic rock formed by fissure eruption，which mainly consists of breccia-bearing welded tuff，breccia-bearing crystal tuff and sedimentary tuff. The seismic reflection shows low frequency，poor continuity，medium strong amplitude or weak amplitude. The sweet spot distribution of tuff reservoirs predicted by multi-parameter inversion body fusion technology has a high coincidence rate with drilling data. The average value of tuff reservoir drilling catching rate is 92.8%，and the average gas reservoir drilling catching rate is 81.0%，among which 12 wells has obtained industrial gasflow. The reservoirs of Huajia structural belt and Guojia fault step belt are mainly composed of breccie-bearing welded tuff and breccie-bearing crystal tuff，with developed faults，making these two areas as the high-quality reservoir zones.（2）The lithology and lithofacies template formed by matching the well log and seismic facies characteristics of the tuff in the study area were useful to identify seismic facie of the tuff. It was confirmed that the crater and proximal crater facie characterized by amplitude attributes are favorable lithology distribution areas. （3）High-quality source rocks developed in Huoshiling Formation，Shahezi Formation and Yingcheng Formation have a thickness of more than 300 meters，with TOC of 0.26%-5.08%，0.10%-5.55%，0.10%-9.74%，S1+S2 of 0.24-8.23 mg/g，0.12-18.15 mg/g，0.25-2.86 mg/g，and Ro of 0.6%-1.3%，1.1%-1.6%，1.0%-2.2%，respectively. With the characteristic of high abundance and moderate maturity，they lay a good material foundation for a large-scale reservoir formation.（4）The tuff gas reservoir in the study area is a set of tight gas reservoirs with source and reservoir lateral connection and high enrichment. The accumulation is mainly controlled by structural styles，faults development and hydrocarbon supply windows. The imbricated fault-bending folds formed by tension and extension，is the major factor to control the degree of hydrocarbon enrichment，and the size of faults and hydrocarbon supply windows determine the gas reservoir scale.
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Oil and gas migration characteristics of lithologic reservoirs of Neogene Minghuazhen Formation in Bozhong A-2 area，Bozhong Sag
CHENG Yan, WANG Bo, ZHANG Tongyao, QI Yumin, YANG Jilei, HAO Peng, LI Kuo, WANG Xiaodong
2024, Vol.36(5): 46–55
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doi: https://doi.org/10.12108/yxyqc.20240505
By analyzing the characteristics of source rocks and comparing the biomarker parameters of crude oil samples from typical wells，the crude oil sources and its migration and accumulation patterns of lithologic reservoirs of the lower Minghuazhen Formation of Neogene in Bozhong A-2 area in the southwest belt of Bozhong Sag were studied. The results show that：（1）The source rocks of the third member of Dongying Formation （E3d3）and the first and third members of Shahejie Formation（E2s1，E2s3）are developed longitudinally in the southwest belt of Bozhong Sag. The source rocks of E3d3 have C19TT predominance，a high Ts abundance value and a “V”-shaped distribution of C27-C28-C29 regular sterane. The source rocks of E2s1 have C23TT predominance， similar Ts and Tm abundance values，a high abundance value of gammacerane and a “L”-shped distribution of C27-C28-C29 regular sterane. The source rocks of E2s3 have C21TT or C23TT predominance，high Ts abundance value，and a “V”-shaped distribution of C27-C28-C29 regular sterane，with C27 predominance.（2）The difference distribution of physical parameters and gas chromatogram of crude oil shows that the filling capacity of crude oil in the southeast well area of Bozhong A-2 reservoir is stronger than that in the middle well area. The C27-C28-C29 regular sterane distributed in a “L” shape and the peak value of 4-methylsteranes is large. In the upper part of the lower Minghuazhen Formation，the C19TT/C23TT is smaller，the MPI1 and MPI2 parameters are larger，total oil has a slightly heavy carbon isotope，indicating that the oil source is mainly supplied by E2s1 and supplemented by E2s3.（3）1-methylphenanthrene，9-methylphenanthrene，C29ααS/（S+R），C29ββ/ αα+ββ），dibenzothiophene series and QGF index parameters change regularly in each well of Bozhong A-2 reservoir，indicating that the crude oil is mainly charged from east to south to northwest. The comparison results of crude oil biomarker show that the deep crude oil in the southwest belt of Bozhong Sag firstly accumulated in Guantao Formation in Bozhong A-4 reservoir，transported vertically to the shallow lower Minghuazhen Formation，and then migrated horizontally along the wide sand bodies to lower Minghuazhen Formation of Bozhong A-2 reservoir，thus forming the current lithologic reservoirs.
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Provenance transformation and sedimentary filling response of Mesozoic in Halahatang-Hade area，Tarim Basin
YI Zhenli, SHI Fang, YIN Taiju, LI Bin, LI Meng, LIU Liu, WANG Zhukun, YU Ye
2024, Vol.36(5): 56–66
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doi: https://doi.org/10.12108/yxyqc.20240506
The sediment supply and infilling evolution of the Mesozoic in Halahatang-Hade area of Tarim Basin were studied by analyzing the changes in paleogeomorphic morphology，distribution of sedimentary systems， stratigraphic structure and sand-bodies development characteristics，based on the main measuring method of mineral composition analysis，calculation of sand to land ratio，seismic attribute analysis and logging response feature recognition. The results show that：（1）The provenance of the Triassic mainly came from the Tianshan orogenic belt in the northeast，with ZTR coefficient gradually increasing from the northern area to the central sag. During the Jurassic and Cretaceous，the provenance mainly came from the orogenic belt of Kunlun Mountains in the southeast and south. The ZTR coefficient of this period is gradually increasing from the northern and southern areas to the central sag.（2）In the late Triassic，with the proliferation of the Paleo-Tethys Ocean，the weakening of the uplift of the Tianshan Mountains in the north of the study area and the intensification of the uplift of the Kunlun Mountains in the south are the main reasons for this provenance transformation.（3）During the Triassic，the depression and deposition centers were located in the south of the study area，and a set of braided river delta and deep-water lake deposits in the NE-SW direction were mainly developed. During the Jurassic and Cretaceous，the depression and deposition centers migrated to the north of the study area，and a set of braided river delta and shallow lake deposits were developed in the direction of SE-NW and S-N respectively.（4）During the Triassic，the progradation direction of sand-bodies was mainly in the NE-SW direction. During the Jurassic and Cretaceous，the progradation direction of sand-bodies was mainly in the SE-NW and S-N direction respectively.（5）The exploration areas for Triassic lithologic reservoirs are located in the southwest of the study area，while the exploration areas for Jurassic and Cretaceous lithologic reservoirs are located in the northwest and north of the study area.
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Characteristics of multi-phase thermal fluid activity and natural gas migration-accumulation of Cenozoic in No. 2 fault zone of Qiongdongnan Basin
HUANG Xiangsheng, YAN Zhuoyu, ZHANG Dongfeng, HUANG Heting, LUO Chengfei
2024, Vol.36(5): 67–76
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doi: https://doi.org/10.12108/yxyqc.20240507
Based on fluid inclusion analysis，organic geochemistry data，and pressure simulation，the multiphase thermal fluid activity and natural gas migration-accumulation in the No. 2 fault zone of the BX19-2 structure in eastern Qiongdongnan Basin were studied. The results show that：（1）The natural gas in the BX19-2 structure primarily consists of hydrocarbon gases and CO2，with the hydrocarbon gases being a mix of coal-derived gas and oil-derived gas. However，there is a significant variation in the composition of natural gas across different gas zones. The shallow gas zones in the Sanya Formation exhibit a relatively high content of hydrocarbon gases（volume fraction of 83.93%）and a low content of organogenic CO2（volume fraction of 7.11%）. In contrast， the deeper gas zones in the Lingshui Formation contain relatively lower concentrations of hydrocarbon gases （volume fraction ranging from 16.10% to 76.63%）and higher concentrations of mantle-derived CO2（volume fraction ranging from 18.70% to 81.56%）.（2）Fluid inclusions and geochemical parameters of rocks indicated that the hydrothermal activity was related to hydrocarbon migration，with variations in the depth and extent of the induced thermal anomalies. There were three phases of hydrocarbon-bearing hydrothermal activities occurred during the late Miocene（approximately 8.8 Ma），Pliocene（approximately 4.5 to 4.1 Ma），and Quaternary （approximately 1.1 to 0.1 Ma），respectively.（3）The hydrothermal fluids primarily utilized faults as major conduits for vertical，efficient，and rapid charging. Mantle-derived CO2 from the deep Baodao Sag was injected during the late Pliocene to Quaternary period（approximately 2.2 to 0.5 Ma），displacing the hydrocarbon gases accumulated in the Lingshui Formation. Therefore，traps near the No. 2 fault zone of the Baodao Sag may pose a risk of encountering gas zones with high CO2 content.
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Simulation and prediction of tight sandstone reservoirs based on waveform facies-controlled inversion：A case study from the second member of Paleogene Kongdian Formation in southern Cangdong sag， Huanghua Depression
ZHOU Ziqiang, ZHU Zhengping, PAN Renfang, DONG Yu, JIN Jineng
2024, Vol.36(5): 77–86
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doi: https://doi.org/10.12108/yxyqc.20240508
On the basis of rock physics analysis，a method combining waveform facies-controlled inversion and simulation，combined with pseudo acoustic impedance reconstruction technology and reservoir parameter indication construction technology based on coordinate rotation，was used to predict the dense sandstone reservoirs of the second member of Paleogene Kongdian Formation in the middle and high slope area of southern Cangdong sag in Huanghua Depression. The results show that：（1）The impedance curve has a poor recognition effect on sandstone and mudstone，while natural gamma ray can be used to effectively distinguish sandstone from mudstone with a limit value of 83 API. The preferred natural potential curve can be used to effectively distinguish sandstone from mudstone with a limit value of -13 mV，and it has a certain ability to distinguish reservoirs from non reservoirs.（2）The reconstructed pseudo acoustic impedance curve improves the recognition ability of sandstone and mudstone. The reservoir indicator curve based on coordinate rotation divides reservoirs and non reservoirs with a threshold value of -10，and the reservoir indicator curve can predict tight sandstone reservoirs. （3） The reservoir prediction method combining waveform facies-controlled inversion and simulation can improve the accuracy of tight sandstone reservoir prediction and reduce the multiplicity of reservoir predictions， with a reservoir prediction accuracy rate of 83.3%.
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Reservoir characteristics and main controlling factors of Jurassic Shaximiao Formation in Wubaochang area，northeastern Sichuan Basin
ZHANG Xiaoli, WANG Xiaojuan, ZHANG Hang, CHEN Qin, GUAN Xu, ZHAO Zhengwang, WANG Changyong, TAN Yaojie
2024, Vol.36(5): 87–98
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doi: https://doi.org/10.12108/yxyqc.20240509
The tight sandstone of Jurassic Shaximiao Formation in northeastern Sichuan Basin has great exploration potential. The reservoir characteristics of Jurassic Shaximiao Formation in Wubaochang area of northeastern Sichuan Basin were studied by using analysis and testing data such as cast thin sections，scanning electron microscopy，cathodoluminescence，X-ray diffraction，properties，mercury injection and homogenization temperature of inclusions. Combined with seismic interpretation results，the reasons for reservoir densification and the distribution characteristics of high-quality reservoirs were analyzed. The results show that：（1）The sandstone reservoirs of Jurassic Shaximiao Formation in Wubaochang area of northeastern Sichuan Basin are characterized by high contents of feldspar and rock debris，general sorting and roundness，low structural maturity and compositional maturity，poor porosity and permeability correlation and poor pore structure，with reservoir porosity mostly less than 6%，permeability mostly less than 1 mD，and mainly developed fractured-porous reservoir.（2）The reservoirs of Jurassic Shaximiao Formation in the study area are in the middle diagenetic stage A. Calcareous cementation leads to local densification of the reservoirs，while burial compaction and laumontite cementation are the main causes for sandstone densification in Shaximiao Formation. Oil and gas continued to charge before and after reservoir densification.（3）Early chlorite rim cementation，atmospheric water leaching and tectonic rupture are the main constructive diagenesis，which are of great significance for the preservation of primary intergranular pores，the formation of secondary dissolved pores and the improvement of reservoir permeability.（4）Sedimentary microfacies，diagenesis and tectonic rupture control the distribution of high-quality reservoirs. The underwater distributary channel with early chlorite rim cementation，weak laumontite cementation，feldspar dissolution and fractures developed is the main development area of high-quality sandstone reservoirs.
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Main controlling factors of shale gas enrichment of Ordovician Wufeng Formation-Silurian Longmaxi Formation in Ningxi area，Sichuan Basin
YANG Xuefeng, ZHAO Shengxian, LIU Yong, LIU Shaojun, XIA Ziqiang, XU Fei, FAN Cunhui, LI Yutong
2024, Vol.36(5): 99–110
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doi: https://doi.org/10.12108/yxyqc.20240510
Through core observation，experimental testing，geophysical interpretation and production dynamic data evaluation，the characteristics of source rocks and reservoirs of Ordovician Wufeng Formation-Silurian Longmaxi Formation in Ningxi area of Sichuan Basin were analyzed. Combined with the history of tectonicthermal evolution-pressure evolution and fault development，the main controlling factors of shale gas enrichment were discussed. The results show that：（1）Organic-rich shale in deep-water shelf facies is developed in Wufeng Formation to the submember of the first member of Longmaxi Formation（Long 11），The kerogen is mainly typeⅠ，with a high organic matter abundance，an average TOC value greater than 3.8%，and an average Ro value greater than 3.0%，indicating that it is in the over mature stage. High-quality source rocks are distributed in Wufeng Formation to the third sublayer of Long11，whilethe fourth sublayer ofLong11 has poor hydrocarbon generation potential.（2）The reservoir conditions of Wufeng Formation toLong11 in the study area are superior， with a high brittleness index and an average value greater than 55%，showing a downward trend from bottom to top. The reservoir spaces include nanoscale inorganic and organic pores，as well as high angle shear fractures and vertical fractures caused by structural factors. The porosity ranges from 2.20% to 5.30%，with an average of 3.84%. The porosity of the first to third sublayers of Long11 is relatively high.（3）The accumulation model of shale gas in the study area is “self generation and self reservoir” within the layer，controlled by source-reservoir configuration，tectonic-thermal evolution，fault level，and fracture development degree. The source-reservoir configuration controls the foundation，and the higher the brittle mineral content and porosity value，the higher the TOC value. Continuous burial of strata before Late Permian（250 Ma）and Emeishan Large Igneous Province promoted the pyrolysis and hydrocarbon generation of shale gas of Wufeng-Longmaxi Formation. From the Late Cretaceous（66 Ma）to the present，tectonic uplift has caused adjustment and loss of gas reservoirs. Faults developed within the layer are beneficial for the preservation of shale gas. The larger the scale of fault development， the less favorable it is for shale gas enrichment. The fracture system controls production capacity，with weak deformation and low fault density in the central part of the syncline，and moderate development of fractures， which is conducive to the enrichment of shale gas. However，the deformation of the structures around the syncline is strong，the fault density is high，and the fracture system is extremely developed，which is destructive to the enrichment of shale gas.
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Lithofacies classification of tight sandstone based on Bayesian Facies-AVO attributes：A case study of the first member of Jurassic Shaximiao Formation in central Sichuan Basin
CHEN Kang, DAI Juncheng, WEI Wei, LIU Weifang, YAN Yuanyuan, XI Cheng, LYU Yan, YANG Guangguang
2024, Vol.36(5): 111–121
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doi: https://doi.org/10.12108/yxyqc.20240511
In seismic exploration，high-velocity or low-velocity tight sandstone reservoirs are often characterized by complex seismic response and strong heterogeneity，and it is difficult to establish a low-frequency model in inversion. With the constraints of AVO intercept and gradient attribute based on Bayesian classification and porosity， the lithofacies of the tight sandstone of Jurassic Shaximiao Formation in central Sichuan Basin was classified. The results show that：（1）Based on elastic wave theory，AVO analysis reflects the underground lithologies and pore fluid properties according to the variation of amplitude with offset. In the application process，AVO forward modeling was carried out based on the relevant parameter combination of different lithologies and fluids，AVO characteristics of known lithologies and fluid properties were obtained and compared with actual seismic records，and then a seismic response model for lithologies and oil and gas identification was established.（2）The crossplot analysis of porosity，intercept and gradient attributes established by model and actual data was used to clarify the internal relationship between the three，determine the classification criteria of lithofacies，fit the probability density function of different lithofacies，and divide the lithofacies of different porosity intervals，to realize the semi-quantitative prediction of porosity.（3）In the application of tight sandstone of the first member of Jurassic Shaximiao Formation in central Sichuan Basin，the lithofacies predicted by probability distribution based on Bayesian classification is up to 93.75% consistent with the actual drilling results，which verifies the feasibility and effectiveness of the method.
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Structural characteristics and hydrocarbon accumulation model of Cambrian Xixiangchi Formation in eastern Sichuan Basin
QIU Yuchao, LI Yading, WEN Long, LUO Bing, YAO Jun, XU Qiang, WEN Huaguo, TAN Xiucheng
2024, Vol.36(5): 122–132
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doi: https://doi.org/10.12108/yxyqc.20240512
The Xixiangchi Formation of the Upper Cambrian is one of the selected field for oil and gas exploration in the eastern Sichuan Basin. Based on the stratigraphic and sedimentary evolution characteristics，the structural patterns and formation mechanism of the Upper Cambrian Xixiangchi Formation in eastern Sichuan Basin were analyzed by using the data of seismic profiles，boreholes，cores and geochemistry. The hydrocarbon accumulation conditions were analyzed from the aspects of source，reservoirs，caprock and migration，and the accumulation model was summarized. The results show that：（1）The deformation of the Cambrian Xixiangchi Formation is constrained by northwestward propagated lower detachment and upper detachment in the Middle Cambrian Gaotai gypsums and Silurian mudstones，and developed four types of structural traps of back-thrust structure， double imbricated structure，fault bend fold structure and salt diapiric-related fault bend fold structure. Two caprocks attribution to both detachment layers further separate the source rocks of the Lower Cambrian Qiongzhusi Formation and Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation from the Xixiangchi Formation that raised harsh accumulation conditions.（2）The Xixiangchi Formation in the study area has the conditions for oil and gas accumulation. The shales of Wufeng Formation to Longmaxi Formation are the main hydrocarbon source rocks，with a thickness of 300-700 m，TOC values of 2%-7% and Ro values of 2.4%-4.0%. The source rocks have strong hydrocarbon generation capacity and are at an over-mature stage. The shoal dolomites transformed by karst and fractures in the later sedimentary stage of Xixiangchi Formation are relatively high-quality and large-scale reservoirs，with a porosity greater than 2.1%. The Yanshanian tectonic uplift and deformation not only formed effective structural traps in Xixiangchi Formation，but also make it break through the Middle-Lower Ordovician cap rock and connect with Wufeng Formation to Longmaxi Formation，achieving lateral migration of oil and gas.（3）A late-stage natural gas accumulation model of the Xixiangchi Formation in the study area is summarized as “younger source rocks juxtaposition with older reservoir rocks are favor to gas migrate laterally into structural traps” . The thrust faults cause the Xixiangchi Formation and the Wufeng Formationto Longmaxi Formation in the hanging wall to be horizontally juxtaposed，forming a structural trap with a lateral connection between source and reservoir，improving the efficiency of hydrocarbon supply and accumulation.
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Characteristics and reservoir control of source rocks of Triassic Chang 7 member in Qingcheng area，Ordos Basin
WANG Zixin, LIU Guangdi, YUAN Guangjie, YANG Henglin, FU Li, WANG Yuan, CHEN Gang, ZHANG Heng
2024, Vol.36(5): 133–144
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doi: https://doi.org/10.12108/yxyqc.20240513
The Chang 7 member of Triassic in Ordos Basin is a key research area for shale oil. Through the determination of total organic carbon，chloroform extraction，rock pyrolysis，XRD whole rock mineral analysis，and scanning electron microscopy observation，the characteristics of source rocks of Triassic Chang 7 member in Qingcheng area of Ordos Basin were analyzed. A three-dimensional electrical logging model of organic carbon and logging curves was established by using multiple regression linear method，clarifying the spatial distribution characteristics of the source rocks and their reservoir control effects. The results show that：（1）The average TOC values of shale samples from Chang 71，Chang 72 and Chang 73 submembers in Qingcheng area of Ordos Basin are 5.01%， 6.04% and 6.76%，respectively，and the average values of chloroform bitumen “A” are 0.63%，0.67% and 0.73%，respectively. The overall organic matter types are mainly type Ⅱ1 and type Ⅱ2，which are in mature to high-mature stage. The oil content and mobility are good，reaching a good to excellent source rock level.（2）The shale samples are mainly composed of quartz feldspar and clay minerals. The pore types are mainly primary intergranular pores，intercrystalline pores and constricted fissures in organic matters，but the pore size distribution of each sample is different.（3）The lower limit of TOC in source rocks in the study area is 1.50%. The 72 submember near Qingcheng area and the 73 submember near Qingcheng and Huanxian areas are the main effective source rock development areas.（4）The TOC content and spatial distribution characteristics of effective source rocks affect the oil content of shale reservoirs，and the TOC content directly determines the level of oil production.
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Characteristics of deep-water deposits and evolution law of Triassic Chang 7 reservoir in southeastern Ordos Basin
YIN Hu, QU Hongjun, SUN Xiaohan, YANG Bo, ZHANG Leigang, ZHU Rongxing
2024, Vol.36(5): 145–155
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doi: https://doi.org/10.12108/yxyqc.20240514
Guided by the theory of sedimentology，the data of outcrops，drilling cores and logging were used to study the characteristics of deep-water deposits，including facies markers and sedimentary microfacies types，of Triassic Chang 7 reservoir in southeastern Ordos Basin，and the evolution law was revealed. The results show that：（1）Facies markers of deep-water deposits of Triassic Chang 7 reservoir in southeastern Ordos Basin include sedimentary structures such as horizontal bedding，Bouma sequence，trough mode，sliding and slump structure， tearing debris，mud-clad gravel，containing deep-water bivalves and fish fossils. The total suspended content in the grain size probability curve is large and the sorting is poor，and the features of zigzag，teethed box-bell-finger shaped and mudstone baseline can be seen on the logging curve.（2）The provenance of Chang 7 reservoir in the study area mainly comes from the northeast and south，with the development of deep to semi-deep lake，sublacustrine fan and shallow lake，and shallow lake sediment. The sublacustrine fan includes two types of gravity flow: turbidity flow and sandy debris flow. It can be further divided into microfacies such as gravity flow main channels，overflow deposits，gravity flow branch channels，inter branch channels，and lobes. The main channels of the sublacustrine fan mainly developed sandy debris flow deposits，while the branch channels and lobes are mainly developed turbidite deposits.（3）The sedimentary evolution law of Chang 7 reservoir in the study area is as follows: deep to semi-deep lake and sublacustrine fan deposits were developed in the central and southern parts of the study area，and shallow lake deposits were developed in the northeastern part. Four sublacustrine fans from the northeast direction were developed in the study area and two sublacustrine fans from the south were developed. The boundary between semi-deep lake and shallow lake extends along Yan’an-Ganquan belt from northwest direction. During the sedimentary period of Chang 73，the range of deep to semi-deep lake was the largest，and the sublacustrine fan was locally developed. During the sedimentary period of Chang 72 and Chang 71，the development of sublacustrine fan gradually increased，while the range of deep lake to semi-deep lake gradually lessened，showing an overall trend of interactive sedimentation between deep lake to semi-deep lake and lacustrine fans.
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Characteristics of source rocks and thermal evolution simulation of Permian Pingdiquan Formation in Dongdaohaizi Sag，Junggar Basin
YANG Haibo, FENG Dehao, YANG Xiaoyi, GUO Wenjian, HAN Yang, SU Jiajia, YANG Huang, LIU Chenglin
2024, Vol.36(5): 156–166
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doi: https://doi.org/10.12108/yxyqc.20240515
Based on the data of drilling，mud-logging，wire-logging and source rock analysis and testing，the hydrocarbon generation potential and thermal evolution history of the source rocks of the Permian Pingdiquan Formation in Dongdaohaizi Sag of Junggar Basin were systematically studied. The results show that：（1）The hydrocarbon source rocks of the Permian Pingdiquan Formation in Dongdaohaizi Sag of Junggar Basin are mainly darkgray and gray black mudstones，which are dark in color and generally large in thickness. The thickness gradually increases from the northeastern slope area to the center of the sag，and gradually decreases toward the western Mosuowan uplift，with a maximum thickness of 536 m.（2）The organic matter abundance of the source rocks of Pingdiquan Formation in the study area is evaluated as medium to excellent levels，with the highest organic matter abundance in the first member of Pingdiquan Formation in the vertical direction and in Dinan 7 and Dinan 19 well areas in the northeast of the sag on plane. The organic matter type is mainly type Ⅱ2-Ⅲ，with a few type Ⅱ1，and it is the best in the second member of Pingdiquan Formation in the vertical direction. The organic matter type of source rocks near the central sag is mainly type Ⅱ1-Ⅱ2 on plane.（3）The simulation results of thermal evolution history show that the source rocks in the sag and slope areas reached their hydrocarbon generation peaks in the Late Triassic and Late Jurassic，respectively，and are currently in the high mature stage and mature stage，respectively.（4）There are two types of hydrocarbon accumulation models in the study area： “lowergeneration and upper-reservoir” and “self-generation and self-reservoir” . The source rocks of Pingdiquan Formation and the reservoirs of the Upper Urho Formation form “lower-generation and upper-reservoir” reservoirs， while the high-quality source rocks of the first and second members of Dingdiquan Formation and the small-scale fan delta deposits at the edge of the lake basin form “self-generation and self-reservoir” reservoirs within the Pingdiquan Formation，both of which have great potential for oil and gas exploration.
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Formation mechanism and evolution characteristics of overpressure in deep Permian in eastern Fukang Sag，Junggar Basin
WEI Chenglin, ZHANG Fengqi, JIANG Qingchun, LU Xuesong, LIU Gang, WEI Yanzhao, LI Shubo, JIANG Wenlong
2024, Vol.36(5): 167–177
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doi: https://doi.org/10.12108/yxyqc.20240516
Based on the data of drilling，mud-logging，wire-logging，and measured formation pressure，the basin simulation technology considering multiple overpressure mechanisms was applied to identify the overpressure origins of Permian in the eastern Fukang Sag of Junggar Basin，and the evolution characteristics of overpressure of various origins were quantitatively restored. The results show that：（1）The Permian in the eastern Fukang Sag develops weak to strong overpressure，the formation pressure coefficient ranges from 1.36 to 1.88，and the excess pressure ranges from 12 to 49 MPa. The overpressure developed in different structural parts is obviously different. The overpressure in the sag is the highest，with formation pressure coefficient of 1.50-1.88 and excess pressure of 23-49 MPa，followed by slope zone，with a formation pressure coefficient of 1.52-1.79 and excess pressure of 24-37 MPa. It is relatively weakest in the uplift，with formation pressure coefficient ranging from 1.36 to 1.59 and excess pressure ranging from 12 to 23 MPa.（2）The origins of overpressure in the strata with different lithologies in the study area are different. The overpressure in the source rocks of Lucaogou Formation is caused by hydrocarbon generation and undercompaction，it is caused by overpressure transference and undercompaction in the reservoirs of the Upper Urho Formation，while it is caused by undercompaction in the mudstone cap rocks of the Upper Urho Formation.（3）The overpressure in the source rocks of the Lucaogou Formation and the mudstone cap rocks of the Upper Urho Formation in the study area has a continuous increasing characteristic. The contribution rate of hydrocarbon generation and pressure increase of the source rocks of the Lucaogou Formation gradually increases along the uplift，slope zone to the sag. The undercompacted pressure increase of the mudstone cap rocks of the Upper Urho Formation also shows the same changing trend. The overpressure in the reservoirs of Upper Urho Formation slowly increased from the Late Triassic to the Late Jurassic， then rapidly increased from the Late Jurassic to the Early Cretaceous，and slowly increased from the Late Cretaceous to present. The contribution rate of the pressurization of overpressure transference to the current reservoir overpressure ranges from 58.46% to 78.86%.
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Natural depletion characteristics and pressure maintenance strategies of faultcontrolled fracture-cavity condensate gas reservoirs in Shunbei Oilfield
SU Hao, GUO Yandong, CAO Liying, YU Chen, CUI Shuyue, LU Ting, ZHANG Yun, LI Junchao
2024, Vol.36(5): 178–188
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doi: https://doi.org/10.12108/yxyqc.20240517
The fault-controlled fracture-cavity condensate gas reservoirs in Shunbei Oilfield have special geological conditions and are difficult to develop. Based on the actual parameters of the gas reservoirs in Shunbei Oilfield，a quantitative analysis method integrated modeling and simulation was used to characterize the natural depletion of fault-controlled fracture-cavity condensate gas reservoirs，and corresponding pressure maintenance strategies were formulated. The results show that：（1）A hierarchical modeling method based on geophysical attribute depiction was adopted for different types of facies to obtain a fused three-dimensional reservoir facies model. Based on the data of wave impedance，logging data，and well testing interpretation，a three-dimensional porosity model and permeability model was obtained by using human-computer interaction and gradual nesting method. On this basis of two models，combined the fluid model obtained from PVT experiments，a multi-component numerical simulation model representing the characteristics of the fault-controlled fracture-cavity condensate gas reservoirs in the region can be obtained.（2）Retrograde condensation and stress sensitivity are two major factors that constrain the natural depletion development effect of such condensate gas reservoirs. The retrograde condensation shortens the stable production time of oil，increases the gas oil ratio，and reduces cumulative oil production. Fractures in reservoirs with stress sensitivity may close under certain stress conditions，resulting in the difficulty to produce some reserves connected to the fractures.（3）CH4 is the optimal injection medium for pressure maintenance development，and the best injection effect occurs when it is injected slightly above the dew point pressure. Injection-production rate and injection time are positively correlated with the oil production increment，but the oil replacement rate decreases as the injection volume increases. For the injection-production well group，the scheme which adopts continuous injection and production mode first and then switch to pulse injection and continuous production mode is the best strategy for increasing oil production while preventing gas channeling. For the isolated well，the huff and puff injection and production method can be used to improve the condensate oil recovery. Further，both the injection and production wells are deployed in a cave，which is easier to make the injected gas act on the main reserves in the cave and drive out the main reserves in a directional way. Meanwhile，ensuring sufficient distance between injection and production wells is beneficial for preventing gas channeling and increasing the swept volume.