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Prediction method for lithologic reservoirs in Doshan slope zone of South Turgai Basin，Kazakhstan
HE Wenyuan, CHEN Keyang
2024, Vol.36(4): 1–11
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209 )
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383
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Exploration achievements and prospects for shale gas of Middle-Upper Permian in Hongxing area，eastern Sichuan Basin
BAO Hanyong, ZHAO Shuai, ZHANG Li, LIU Haotian
2024, Vol.36(4): 12–24
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205 )
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(20898 KB)
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324
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Hydrocarbon accumulation model and main controlling factors of tight oil of the fourth member of Cretaceous Yingcheng Formation in Shuangcheng fault depression，Songliao Basin
YANG Weihua
2024, Vol.36(4): 25–34
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164 )
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(7722 KB)
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251
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Natural fracture characteristics and fracture network simulation in shale reservoirs of Permian Lucaogou Formation in Jimsar Sag
XU Tianlu, WU Chengmei, ZHANG Jinfeng, CAO Aiqiong, ZHANG Teng
2024, Vol.36(4): 35–43
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173 )
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(9742 KB)
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241
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Morphology，distribution and main controlling factors of modern distributive fluvial system in Tarim Basin
MENG Qinghao, ZHANG Changmin, ZHANG Xianghui, ZHU Rui, XIANG Jianbo
2024, Vol.36(4): 44–56
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155 )
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(28600 KB)
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257
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Accumulation mechanism of overpressured lithologic reservoirs of the third member of Paleogene Shahejie Formation in northern Dongpu Sag
ZHANG Lei, LI Sha, LUO Bobo, LYU Boqiang, XIE Min, CHEN Xinping, CHEN Dongxia, DENG Caiyun
2024, Vol.36(4): 57–70
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157 )
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241
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Distribution characteristics and controlling factors of tight oil of Triassic Chang 7 member in northern Shaanxi area，Ordos Basin
MOU Feisheng, YIN Xiangdong, HU Cong, ZHANG Haifeng, CHEN Shijia, DAI Linfeng, LU Yifan
2024, Vol.36(4): 71–84
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184 )
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271
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Sedimentary characteristics of fan delta front of the fourth member of Cretaceous A’ershan Formation in Bayindulan Sag，Erlian Basin
ZHOU Hongfeng, WU Haihong, YANG Yuxi, XIANG Hongying, GAO Jihong, HE Haowen, ZHAO Xu
2024, Vol.36(4): 85–97
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164 )
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215
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Geological modeling and“sweet spot”prediction of Permian coal measures shale reservoirs in Yushe-Wuxiang block，Qinshui Basin
SHEN Youyi, WANG Kaifeng, TANG Shuheng, ZHANG Songhang, XI Zhaodong, YANG Xiaodong
2024, Vol.36(4): 98–108
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168 )
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(4160 KB)
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216
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Identification and reservoir significance of Carboniferous karst paleogeomorphology in Wubaiti area，eastern Sichuan Basin
WANG Tongchuan, CHEN Haoru, WEN Longbin, QIAN Yugui, LI Yuzhuo, WEN Huaguo
2024, Vol.36(4): 109–121
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132 )
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173
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Sedimentary characteristics and sources of shale of Dongyuemiao member of Lower Jurassic Ziliujing Formation in eastern Sichuan Basin
ZOU Liansong, XUWenli, LIANG Xiwen, LIU Haotian, ZHOU Kun, HOU Fei, ZHOU Lin, WEN Huaguo
2024, Vol.36(4): 122–135
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148 )
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174
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Tight reservoir characteristics and favorable areas prediction of Lower Cretaceous Nantun Formation in central fault depression zone of Hailar Basin
TIAN Ya, LI Junhui, CHEN Fangju, LI Yue, LIU Huaye, ZOU Yue, ZHANG Xiaoyang
2024, Vol.36(4): 136–146
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149 )
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198
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Characteristics of shale pore structure and its oil and gas geological significance of Lower Cambrian Niutitang Formation in Fenggang area，northern Guizhou
ZHU Biao, ZOU Niuniu, ZHANG Daquan, DU Wei, CHEN Yi
2024, Vol.36(4): 147–158
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150 )
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182
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Characteristics and evolution model of hydrocarbon accumulation of Cambrian Longwangmiao Formation in the north slope of central Sichuan paleo-uplift
LU Keliang, WU Kangjun, LI Zhijun, SUN Yonghe, XU Shaohua, LIANG Feng, LIU Lu, LI Shuang
2024, Vol.36(4): 159–168
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156 )
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217
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Numerical simulation of fracture propagation law of in-fracture temporary plugging and diverting fracturing in tight reservoirs
TANG Shukai, GUO Tiankui, WANG Haiyang, CHEN Ming
2024, Vol.36(4): 169–177
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154 )
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268
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Water invasion performance and main controlling factors for edge-water gas reservoirs
QIN Zhengshan, HE Yongming, DING Yangyang, LI Baihong, SUN Shuangshuang
2024, Vol.36(4): 178–188
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156 )
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Prediction method for lithologic reservoirs in Doshan slope zone of South Turgai Basin，Kazakhstan
HE Wenyuan, CHEN Keyang
2024, Vol.36(4): 1–11
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209 )
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383
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doi: https://doi.org/10.12108/yxyqc.20240401
By comprehensively utilizing drilling，logging and seismic data，the sedimentary characteristics of the central slope zone in the Doshan block of the South Turgai Basin in Kazakhstan were analyzed，and a method for predicting lithologic reservoirs was proposed. The lithologic traps were identified，and their prediction results were verified through seismic attributes. The results show that：（1）During the sedimentation of the MiddleLower Jurassic in Doshan slope zone of South Turgai Basin in Kazakhstan，there were strong tectonic activities， with a small number of faults developed，mainly lacustrine sedimentation. It can be divided into three sedimentary periods：SQ4-SQ6，corresponding to the Ebalin Formation（J1ab），Doshan Formation（J2ds），and Karagansai Formation（J2kr），respectively. During the SQ6 period，large-scale lake intrusion occurred，and the fan delta was distributed in a skirt like pattern on one side of the edge fault，and the semi-deep lake area expanded.The delta front is a favorable facies zone for the development of lithologic traps.（2）The reservoir prediction method is to determine the formation boundary based on well seismic calibration results，correct the influence of wellbore diameter through rock physics analysis based on acoustic curve reconstruction，identify sand bodies through forward modeling based on tuning thickness，and identify single sand layers through high-resolution lithologic reservoir seismic inversion technology.（3）The lithologic traps in the study area are mainly distributed in the Middle to Lower Jurassic，which are developed on a series of structural belts with slope break controlled sand. The seismic attribute analysis results have a high degree of agreement with sedimentary characteristics.（4）A series of lithologic traps are developed in the slope break of Middle-Lower Jurassic in the study area，which exhibit strong amplitude and high impedance characteristics on high-resolution seismic sections，making it a favorable exploration area.
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Exploration achievements and prospects for shale gas of Middle-Upper Permian in Hongxing area，eastern Sichuan Basin
BAO Hanyong, ZHAO Shuai, ZHANG Li, LIU Haotian
2024, Vol.36(4): 12–24
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205 )
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doi: https://doi.org/10.12108/yxyqc.20240402
Based on tectonic，core and logging data，a systematic analysis was conducted on the sedimentary evolution，reservoir characteristics and shale gas enrichment models of Middle-Upper Permian shale in Hongxing area of eastern Sichuan Basin by means of electron microscope scanning，low-temperature N2 adsorption experiments，high-pressure mercury pressure experiments and basin simulation，the favorable exploration areas were identified，the exploration results and significance were summarized. The results show that：（1）The sedimentary evolution of Middle-Upper Permian in Hongxing area is characterized by open platform facies in QixiaMaokou Formation；platform-shelf facies at the bottom of the fourth member of Maokou Formation，with fast facies change，while slope-shelf facies at the top of the fourth member of Maokou Formation，with strata denuded， thicker in the south and thinner in the north；marine-terrestrial transitional coastal swamp-lagoon facies at the bottom of the first member of WujiapingFormation，while platform-slope-shelf facies at the top of the first member of WujiapingFormation，with small distribution and fast facies change；slope-shelf facies in the second member of WujiapingFormation，which was controlled by paleoclimate，volcanic activity，paleoclimate，and volcanic activity from early to late，with high paleoproductivity during the middle to late sedimentary periods and average TOC greater than 8.00%.（2）Two sets of high-quality shales were developed in the shelf facies areas in the fourth member of Maokou Formation and the second member of Wujiaping Formation，with high organic carbon and high calcite content. Their thicknesses of organic-rich shales are 19 m and 25 m，respectively. The pores are dominated by organic pores，and the structures are mainly micropores and mesopores. The thinly interbedded mixed shale phases of carbon-rich tuff and the thinly interbedded siliceous shale phases of high carbon tuff are high-quality phases，with porosity of 6.27% and 6.43%，TOC of 10.11% and 9.35%，gas saturation 92.59% and 91.81%，and brittleness index of 55.24% and 61.19%，respectively. They are the dual“sweet spots”of geology and engineering.（3）The widely developed Permian stratified algae in the study area are the main source of organic matters. During the mian hydrocarbon expulsion period of Jurassic，the tectonic was stable，with less hydrocarbon expulsion of Permian hydrocarbon source rocks. Middle Jurassic to the early stage of Early Cretaceous was the main gas generation period，with weak tectonic activity and good preservation conditions for shale gas. The gas generation process has been completed and is currently in the mature to over mature stage，with a Ro value of about 2.1%，indicating huge exploration potential.（4）Jiannan，Longjuba and Sanshing blocks are favourable exploration areas，with Jiannan block having the greatest potential. The third sublayer of the fourth member of Maokou Formation and the third layer of the second member of Wujiaping Formation are target-window layer segments of high-quality layers.
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Hydrocarbon accumulation model and main controlling factors of tight oil of the fourth member of Cretaceous Yingcheng Formation in Shuangcheng fault depression，Songliao Basin
YANG Weihua
2024, Vol.36(4): 25–34
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doi: https://doi.org/10.12108/yxyqc.20240403
By comprehensively utilizing seismic data and core analysis testing data such as inclusion homogenization temperature，rock pyrolysis，and reservoir properties，the types，distribution characteristics，and accumulation stages of tight oil reservoirs of the fourth member of Cretaceous Yingcheng Formation（Ying-4 member） in Shuangcheng fault depression of Songliao Basin were analyzed，and the main controlling factors for tight oil accumulation were studied from four aspects：source rock evaluation，reservoir characteristics，tectonic activities，and transport system. The results show that：（1）The distribution pattern of tight oil reservoirs of Ying-4 member in Shuangcheng fault depression of Songliao Basin is as follows：from the central trough to the slopes on both sides，there are lithologic reservoirs within the source，near source fault-lithologic reservoirs，stratigraphic reservoirs，and far source structural reservoirs. The reservoir is one-stage hydrocarbon accumulation， and the main accumulation satge is from the late sedimentary period of Yaojia Formation in Late Cretaceous to the early sedimentary period of Nenjiang Formation（80-78 Ma）.（2）The lacustrine mudstone and oil shale developed in the lower submember of Ying-4 member（K1yc4）in the study area have great potential for oil and gas generation. The central depression is the center of hydrocarbon generation and expulsion，with high hydrocarbon generation and expulsion intensities of（20-300）×104 t/km2 and（5-53）×104 t/km2，respectively. The fan delta conglomerate sandstone reservoirs developed in the upper K1yc4 has a large thickness and good continuity. The front sand bodies extend into the lake，with an average porosity of 11.4% and an average permeability of 0.95 mD. Among them，relatively high-quality reservoirs with porosity greater than 8.0% and permeability higher than 0.85 mD are favorable targets for tight oil enrichment. Deep traps of various types formed at the end of Quantou Formation in Early Cretaceous，structure during the main accumulation stage was weak，which is conducive to the formation and preservation of oil reservoirs. The multi type three-dimensional transport system composed of faults，unconformities，and connected sand bodies is the main pathway for oil and gas migration， promoting the convergence of oil and gas towards the slopes on both sides.（3）The tight oil reservoir accumulation in the study area is controlled by the coupling of“source rock-fan delta sandbody-transport system”，and is distributed in a ring-shaped pattern around hydrocarbon generating troughs，with characteristics of large-scale distribution and local enrichment. Three reservoir accumulation models are developed，including“reservoir overriding source rock，and they connect with reticular-blanket transportations，oil accumulate within the fan delta” in center depression，“source and reservoir close proximity，fault sandstone matching，and migration along the fault step”in eastern slope，and“source and reservoir separation，“Y”- shaped migration and accumulation，and enrichment in tectonic highs”in western steep slope. Fan bodies enclosed by mudstone or in contact with mudstone interlayers，fault-lithologic and stratigraphic traps near oil source faults，and anticline and fault anticline traps near oil source faults are favorable exploration targets for the central depression，eastern slope，and western steep slope，respectively.
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Natural fracture characteristics and fracture network simulation in shale reservoirs of Permian Lucaogou Formation in Jimsar Sag
XU Tianlu, WU Chengmei, ZHANG Jinfeng, CAO Aiqiong, ZHANG Teng
2024, Vol.36(4): 35–43
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doi: https://doi.org/10.12108/yxyqc.20240404
Based on core，seismic，logging，and microseismic monitoring data，and under the constraints of natural fracture models and geostress models，the characteristics of natural fractures and their impact on the expansion of fracture networks in Permian Lucaogou Formation in Jimsar Sag were studied through fracture network simulation in shale reservoirs. The results show that：（1）The natural fractures of Permian Lucaogou Formation in Jimsar Sag include bedding fractures and structural fractures，with the bedding fractures as the main type，having a large number and small dip angles. The average number of fractures is 251，and the fracture surface density is 0.58-1.34 per meter，with an average of 0.93 per meter. The dip angle of the structural fractures is 70°-95°，and the number of fractures is significantly less than that of the bedding fractures. According to the formation time and occurrence，the structural fractures can be divided into type Ⅰ and type Ⅱ structural fractures. （2）The minimum horizontal principal stress in the study area is 50.41-55.22 MPa，and the maximum horizontal principal stress is 53.52-74.43 MPa，which is conducive to the extension of hydraulic fracturing network. There are stress barriers in the vertical direction of Lucaogou Formation，and the maximum interlayer stress difference can reach 12 MPa，so it is not easy for the artificial fracture to penetrate the layers during hydraulic fracturing. （3）The fracturing transformation of shale of Lucaogou Formation in the study area is mainly to activate the highangle structural fractures. 96.45% of the fracturing fractures are“T-shaped”，while the“cross-shaped”and “straight -shaped”fractures only account for 2.24% and 1.21%，respectively. The half-length of the fractures of Lucaogou Formation is 70-100 meters，and the height is 10-30 meters. When adjacent to faults，due to the excessive fracture length，well-channeling is prone to occur.
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Morphology，distribution and main controlling factors of modern distributive fluvial system in Tarim Basin
MENG Qinghao, ZHANG Changmin, ZHANG Xianghui, ZHU Rui, XIANG Jianbo
2024, Vol.36(4): 44–56
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doi: https://doi.org/10.12108/yxyqc.20240405
Combined with the results of field geological investigation，the geographic information software was used to measure the distributive fluvial system（DFS）developed in and around Tarim Basin，and the differences in geometric parameters of DFS in different regions of the basin were compared to study the development rules and main controlling factors of DFS. The results show that：（1）The sedimentary system of Tarim Basin can be divided into four types：DFS，axial sedimentary system，desert sedimentary system and other sedimentary systems. The DFS has the highest proportion，accounting for about 36%，and mainly developed in south Tianshan Mountain piedmont area，the Kunlun Mountain piedmont area and the Altun piedmont area.（2）The DFS in Tarim Basin can be divided into three types：small，large and mega DFS，with the largest scale of DFS deve-loped in the Kunlun Mountain piedmont area，followed by Altun Mountain piedmont area，and the smallest scale in the south Tianshan Mountain piedmont area. Large-scale DFS controls the pattern of DFS. Among the 846 measured DFS， the proportion of small-scale DFS in the basin is 89.4%，and the total area accounts for 5%. The proportion of mega DFS is 2.2%，and the total area accounts for 68%.（3）The main geometric parameters of DFS include area，radius，and slope. The goodness of fit R2 between area and radius is 0.966 4，indicating a strong positive correlation. The goodness of fit R2 between slope and radius is 0.463 0，indicating a certain degree of negative correlation. The goodness of fit R2 between slope and area is 0.498 8，indicating a certain degree of negative correlation.（4）The main controlling factors for the morphology and distribution of DFS include climate，hydrology and tectonic uplift degree. Under extreme arid climate，rivers are more likely to dry up，and the development scale of DFS is limited. The river runoff of DFS has a strong correlation with radius，and the larger the river runoff，the larger the scale of DFS development. The degree of tectonic uplift plays a dominant role，and the higher the mountain uplift，the easier it is to develop larger scale DFS. Negative structural units within the basin promote the development of DFS，while the positive structural units hinder the development of DFS.
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Accumulation mechanism of overpressured lithologic reservoirs of the third member of Paleogene Shahejie Formation in northern Dongpu Sag
ZHANG Lei, LI Sha, LUO Bobo, LYU Boqiang, XIE Min, CHEN Xinping, CHEN Dongxia, DENG Caiyun
2024, Vol.36(4): 57–70
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doi: https://doi.org/10.12108/yxyqc.20240406
The processes of hydrocarbon generation，migration and accumulation are complex with tight reservoirs and widespread overpressure in the deep area of Dongpu Sag. A systematic study was conducted on the formation mechanism of overpressure，the effects of overpressure on source rocks and reservoirs，as well as the dynamics of hydrocarbon migration in the third member of Paleogene Shahejie Formation in northern Dongpu Sag by using wire-logging，mud-logging，drilling，and geochemical analysis data，and the accumulation mechanisms of deep overpressured lithologic reservoirs were elucidated. The results show that：（1）There are five types of overpressured lithologic reservoirs of the third member of Paleogene Shahejie Formation in northern Dongpu Sag， which are three pure lithologic reservoirs and two compound reservoirs. The pure lithologic reservoirs include updip pinch-out sandstone reservoirs，sand lens reservoirs and fractured reservoirs，while the compound reservoirs are lithologic-structural reservoirs and structural-lithologic reservoirs. The lithologic reservoirs are mainly distributed in the northern Dongpu Sag，especially around Qianliyuan subsag，Haitongji subsag，Liutun subsag and PuchengWeicheng subsag，with the characteristics of“orderly distribution around sags”.（2）The deep overpressure caused by the thick gypsum salt rocks and the process of hydrocarbon generation in the study area can inhibit the hydrocarbon generation of source rocks，effectively enlarging the oil generation window，enhancing the hydrocarbon generation ability of deep source rocks，and promoting large-scale near source hydrocarbon supply to lithologic reservoirs around the sag. The distribution of high-quality reservoirs is controlled by gypsum salt rocks，rapid burial in the early stage，anti-compaction of overpressure and dissolution in the late stage. The synergistic action of overpressure and buoyancy widely developed in the deep，provides an effective driving force for deep oil and gas migration.（3）The hydrocarbon accumulation model of the eastern sag belt in the study area is“single sag with single source，early miscible phase and late gas phase charging，self-generating and self preserving，hydrocarbon migration and accumulation driven by overpressure”. The hydrocarbon accumulation model of the eastern steep slope zone is“single sag with multi-source，early miscible phase and late gas phase charging，lateral hydrocarbon migration and accumulation driven by overpressure and buoyancy”. The hydrocarbon accumulation model of the western slope zone is“single sag with multi-source，oil phase charging，lateral hydrocarbon migration and accumulation driven by overpressure and buoyancy”. The hydrocarbon accumulation model of the western sag belt is“single sag with single source，oil phase charging，lateral hydrocarbon migration and accumulation driven by overpressure and buoyancy”.
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Distribution characteristics and controlling factors of tight oil of Triassic Chang 7 member in northern Shaanxi area，Ordos Basin
MOU Feisheng, YIN Xiangdong, HU Cong, ZHANG Haifeng, CHEN Shijia, DAI Linfeng, LU Yifan
2024, Vol.36(4): 71–84
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doi: https://doi.org/10.12108/yxyqc.20240407
The data of geochemistry，scanning electron microscopy，core thin sections，logging and oil well production were used to analyze the characteristics of reservoirs，source rocks and the distribution of tight oil of the seventh member of Triassic Yanchang Formation（Chang 7 member）in northern Shaanxi area，Ordos Basin，the controlling factors for differential enrichment of tight oil were discussed from three aspects：source rocks distribution，transport system and source-reservoir configuration，and the reservoir accumulation model was summarized. The results show that：（1）The tight sandstone reservoirs of Chang 7 member in northern Shaanxi area are mainly developed in the first sub-member（Chang 71）and the second sub-member（Chang 72），predominantly composed of gray to gray-white feldspar sandstone and lithic feldspar sandstone. The average porosity of Chang 7 1 and Chang 72 sub-members is 5.56% and 7.32%，respectively，and the average permeability is 0.097 mD and 0.110 mD，respectively. The physical properties of Chang 72 reservoir are better. The pore space is mainly composed of dissolved pores，with a small number of intergranular pores developed.（2）The hydrocarbons in the study area mainly come from two sets of source rocks，including the top of Chang 72and Chang 73，with an average thickness greater than 20 meters. The organic matter abundance is high，with an average total organic carbon （TOC）value of 3.02%. The kerogen types are mainly type I and type Ⅱ1，indicating a period of high hydrocarbon generation，and the average hydrocarbon generation amount is 270.2×104 t/km2. Chang 73 source rocks have greater hydrocarbon generation potential，supplying hydrocarbons to Chang 72 reservoir，and the tight oil in Chang 71 comes from Chang 72 source rocks. The tight oil in Chang 72 reservoir at the end of the delta front subfacies in Xin’anbian area is supplied laterally by lake basin source rocks.（3）The enrichment of tight oil in the study area is controlled by the distribution of source rocks，the connectivity of sand bodies and the sourcereservoir configuration. It is more enriched in Chang 72 and has the largest distribution area in Xin’anbian area， and there is no large-scale tight oil accumulation in Ansai area. The differential tight oil accumulation in the vertical and plane is controlled by the source rock thickness and source-reservoir configuration. The oil-bearing ability is better for lower generation and upper storage，upper-lower generation and middle storage as well as sand and mud interlayers. The scale of tight oil accumulation of Chang 72 at the end of the delta front in Xin’anbian area is larger than that of the main body of the delta front，because the locally connected sand bodies developed at the end of the delta front hinder the lateral migration of hydrocarbon sources in the lake basin.（4）The tight oil in the study area follows a“source-controlled and sand-controlled”accumulation model. The sand bodies in distal river channels and locally connected sand bodies near the source are favorable exploration areas.
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Sedimentary characteristics of fan delta front of the fourth member of Cretaceous A’ershan Formation in Bayindulan Sag，Erlian Basin
ZHOU Hongfeng, WU Haihong, YANG Yuxi, XIANG Hongying, GAO Jihong, HE Haowen, ZHAO Xu
2024, Vol.36(4): 85–97
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doi: https://doi.org/10.12108/yxyqc.20240408
Based on core observation and particle size analysis，combined with mud-logging，wire-logging and seismic data，the sedimentary characteristics，distribution law and development model of fan delta front of the fourth member of Cretaceous A’ershan Formation（K1a4）in B51 well area of Bayindulan Sag in Erlian Basin were studied. The results show that：（1）The lithofacies of K1a4 in B51 well area can be divided into 13 types in four major categories：conglomerate，sandstone，siltstone and mudstone. The grain size distribution curves can be classified into four types，including one suspension segment pattern，low slope two segment pattern，high slope two segment pattern and one roll segment-one bouncing segment-one suspension segment pattern. The logging curves has the characteristics of box-shaped，bell-shaped，funnel-shaped，finger-shaped and flat-shaped， and there are four types of seismic facies ：foreset，lenticular，moundy and subparallel.（2）There are six types of sedimentary microfacies in the fan delta front，including underwater channel，underwater distributary channel，mouth bar，underwater distributary interchannel，sheet sand and distal bar. The K1a4 can be divided into Ⅰ， Ⅱ，Ⅲ sand groups in vertical. During the sedimentary period of Ⅱ and Ⅲ sand groups，the sand bodies of fan delta front were widely distributed，underwater channel and underwater distributary channel were mainly developed. During the sedimentary period of Ⅰ sand groups，lacustrine basin occupied the largest area，sand bodies became finer and thinner.（3）The K1a4 in the study area shows water intrusion depositional sequence from bottom to top，with the development of a retrogradational fan delta front. It is predicted that the underwater channel and underwater distributary channel developed in B51-71 and B51-74 well areas are favorable reservoir facies zones，while mouth bar developed in B51-19 well area is a more favorable reservoir facies zone.
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Geological modeling and“sweet spot”prediction of Permian coal measures shale reservoirs in Yushe-Wuxiang block，Qinshui Basin
SHEN Youyi, WANG Kaifeng, TANG Shuheng, ZHANG Songhang, XI Zhaodong, YANG Xiaodong
2024, Vol.36(4): 98–108
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doi: https://doi.org/10.12108/yxyqc.20240409
The coal measures shale gas resources in Qinshui Basin are abundant，but exploration and development are still in the early stages. Based on drilling，well logging，and seismic interpretation data，combined with organic geochemistry and reservoir physical property experimental test data，a three-dimensional geological modeling technique was used to establish a geological model of coal measures shale from the bottom of Shanxi Formation to the upper Taiyuan Formation of Permian in Yushe-Wuxiang block，Qinshui Basin，and“sweet spot”areas of coal measures shale gas were predicted. The results show that：（1）The Carboniferous-Permian coal measure strata model for Yushe-Wuxiang block reflects that the development of coal measures shale reservoirs is mainly controlled by tectonic activities，showing a distribution pattern of“shallow in the east and deep in the west，and overall continuous”.（2）The sedimentary model based on sequential indicator method indicate that the transition from marine-continental transitional facies to nearshore continental facies sedimentary environments during Taiyuan to Shanxi period in the study area，providing a conducive sedimentary environment for the formation of stable and high-quality shale reservoirs.（3）Facies-controlled attribute modeling achieved spatial distribution simulation and fine characterization of reservoir parameters. The average values of mudstone ratio，porosity，gas content，total organic carbon content，and vitrinite reflectance are 0.57，10.02%，1.21 m3/t，2.18% and 2.45%， respectively，revealing the favorable reservoir capacity，gas content，organic matter abundance，and resource potential of coal measures shale. The brittleness index model indicates favorable zones after shale fracturing. （4）On the basis of fine three-dimensional geological modeling，the three-dimensional grids were assigned integrals，and the geological resource of Permian coal measures shale gas in the study area is estimated at 1 344.98×108 m3. Analytical hierarchy process and fuzzy evaluation methods were used to predict“sweet spot” areas of shale gas. Type I“sweet spot”area for shale gas presenting both geological and engineering advantages， predominantly distributed in the northeastern，central，and northwestern parts of the study area.
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Identification and reservoir significance of Carboniferous karst paleogeomorphology in Wubaiti area，eastern Sichuan Basin
WANG Tongchuan, CHEN Haoru, WEN Longbin, QIAN Yugui, LI Yuzhuo, WEN Huaguo
2024, Vol.36(4): 109–121
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173
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doi: https://doi.org/10.12108/yxyqc.20240410
By comprehensively utilizing drilling，logging，core and seismic data，the identification and characterization of Carboniferous karst paleogeomorphology in Wubaiti area of eastern Sichuan Basin were carried out through the establishment of seismic forward modeling simulation，RGB frequency division fusion technology，and waveform classification analysis. The results show that：（1）The intensity of karstification of Carboniferous in Wubaiti area gradually decreases from west to east. The original sedimentary thickness of Carboniferous in the southeast is larger，but the distribution of residual thickness is uneven，mainly ranging from 10 to 30 meters. The thickness in the northwest is smaller，ranging from 0 to 15 meters.（2）The Carboniferous in the study area can be identified as two secondary karst morphological units，karst highlands and karst slopes，from west to east. The karst slopes can be divided into two tertiary karst morphological units，karst residual hills and karst shallow depressions. Due to the differential dissolution characteristics of shallow depressions on karst slopes，they can also be further divided into steep slope shallow depressions and gentle slope shallow depressions，with residual hills，underground rivers，and sinkholes developed within the karst shallow depressions. The development of karst paleogeomorphology can be identified by the upward and downward characteristics of reflection events，the development of karst breccia，the flattening profile of seismic layers，RGB frequency fusion，and waveform changes.（3）The distribution of karst morphological units of Carboniferous in the study area is controlled by regional tectonics. Shallow depressions and residual hills are mostly elliptical or irregularly elongated in a northwest-southeast direction，and the distribution of underground rivers is consistent with the long axis direction of shallow depressions. Karst morphological units controlled the thickness of strata and the development of dissolved pores. The residual thickness of the residual hills is relatively large，with strong karstification and weak filling. The dissolved pores are more developed，and the average porosity of the reservoir is 4.34%. The residual thickness of shallow depressions in gentle slopes is relatively small，with strong filling effect and undeveloped dissolved pores，and average reservoir porosity of 2.68%. Although the shallow depressions in steep slopes developed a small residual thickness，they are in a strong dissolution and weak filling due to the low water table and strong drainage capacity. The reservoir space of the shallow depressions in steep slopes is developed，and the average porosity of the reservoir is 5.05%. The average porosity of reservoirs on gentle and steep slopes is 3.67% and 3.31%，respectively. The porosity of karst highlands is the smallest，with an average of 2.51%.
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Sedimentary characteristics and sources of shale of Dongyuemiao member of Lower Jurassic Ziliujing Formation in eastern Sichuan Basin
ZOU Liansong, XUWenli, LIANG Xiwen, LIU Haotian, ZHOU Kun, HOU Fei, ZHOU Lin, WEN Huaguo
2024, Vol.36(4): 122–135
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doi: https://doi.org/10.12108/yxyqc.20240411
A set of dark shale is developed in Dongyuemiao member of Lower Jurassic Ziliujing Formation in eastern Sichuan Basin，which has great potential for shale gas exploration and development. By combining the macro tectonic background with the analysis of micro petrological characteristics，and using trace element（including rare earth elements）data，the sedimentary environment and material sources of the shale of Dongyuemiao member of Lower Jurassic Ziliujing Formation in eastern Sichuan Basin were analyzed and discussed. The results show that：（1）Gray shell limestone，gray siltstone，dark gray shell mudstone，gray black shale，and gray-to-dark gray mudstone were deposited from bottom to top in Dongyuemiao member of Lower Jurassic in eastern Sichuan Basin. （2）Rare earth elements of shale of Dongyuemiao member in the study area are characterized by enrichment of light rare earth elements，heavy rare earth elements loss. δCe is a negative anomaly，with an average Ceanom value of -0.015，V（/ V+Ni）average value of 0.70，Sr/Cu average value of 2.43，Sr/Ba average value of 0.16，and（La/ Yb）N average value of 1.32. The sedimentary environment of shale is relatively oxygen-poor and weakly reductive，and it is generally in a warm and humid climate with light water deposition，with fast deposition rate， which is conducive to the enrichment of organic matters.（3）The Zr/Sc-Th/Sc and La/Sc-Co/Th plots show that the sedimentary parent rock in the study area is granite. The values of Th/Sc，Th/Co，Th/Cr and La/Sc are 0.78， 0.65，0.14 and 2.14，respectively，all of which are close to the corresponding element ratios of the upper crust， indicating that the parent rock is mainly granite from the upper crust. The average mass fractions of corrected La and Ce elements are 34.5×10-6 and 70.71×10-6，respectively，and the average values of corrected La/Yb，LREE/ HREE，（La/Yb）N are 11.32，8.13 and 7.67，respectively，and the average value of corrected δEu is 0.82，indicating that they are similar to those of continental island arc. The triangle diagram of La-Th-Sc，Th-Sc-Zr/10 and Th-Co-Zr/10 show that its tectonic background is a continental island arc. Therefore，the provenance of Dongyuemiao member in the study area comes from Daba Mountain in the northeast and Jiangnan ancient land（Xuefeng ancient land）in the southeast.
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Tight reservoir characteristics and favorable areas prediction of Lower Cretaceous Nantun Formation in central fault depression zone of Hailar Basin
TIAN Ya, LI Junhui, CHEN Fangju, LI Yue, LIU Huaye, ZOU Yue, ZHANG Xiaoyang
2024, Vol.36(4): 136–146
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doi: https://doi.org/10.12108/yxyqc.20240412
The data of core analysis，cast thin sections and high-pressure mercury injection were used to study the reservoir characteristics and main controlling factors of Lower Cretaceous Nantun Formation in central fault depression zone of Hailar Basin，and the favorable areas were quantitatively and comprehensively evaluated. The results show that：（1）The rock types of Nantun Formation in in central fault depression zone of Hailar Basin are mainly lithic sandstone and feldspathic lithic sandstone，with reservoir porosity less than 12% accounting for 70.2% and permeability less than 1 mD accounting for 66.3%. It belongs to the category of tight sandstone reservoir，and the reservoir space is a small number of primary pores and a large number of secondary pores.（2）The sedimentary facies control the overall spatial distribution of reservoir properties in the study area. The most favorable sedimentary facies zones of Nantun Formation are braided river delta front and fan delta front subfacies. Compaction has a pore reducing effect on the reservoir，and dissolution is generally developed，forming a large number of intergranular and intragranular dissolved pores，which has a certain improvement effect on the reservoir properties.（3）There are three types of structural belts developed in the central fault depression zone of the basin：gentle slope fault terrace structural belt，steep slope fault terrace structural belt，and trough belt. Among them，the gentle slope fault terrace structural belt and steep slope fault terrace structural belt are the main oil and gas accumulation zones，and the development of their faults is earlier than or contemporaneous with a large number of hydrocarbon expulsion stages of the source rocks，providing channels for oil and gas migration.（4）Five elements of sedimentary facies，porosity，reservoir thickness，sand to stratum ratio and burial depth were superimposed to quantitatively evaluate the favorable reservoir development areas. Among them，type Ⅰ and type Ⅱ high-quality reservoirs are mainly distributed in the gentle slope fault terrace structural belt and steep slope fault terrace structural belt in the central fault depression zone of the basin.
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Characteristics of shale pore structure and its oil and gas geological significance of Lower Cambrian Niutitang Formation in Fenggang area，northern Guizhou
ZHU Biao, ZOU Niuniu, ZHANG Daquan, DU Wei, CHEN Yi
2024, Vol.36(4): 147–158
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doi: https://doi.org/10.12108/yxyqc.20240413
Using whole rock X-ray diffraction（XRD），field emission scanning electron microscopy（FE-SEM） nuclear magnetic resonance（NMR），and low-temperature nitrogen adsorption experimental methods，multi-scale qualitative and quantitative characterization of the pore structure characteristics of shale of Cambrian Niutitang Formation of well Yongfeng 1 in Fenggang area of northern Guizhou was carried out，and its influencing factors and oil and gas geological significance were discussed. The results show that：（1）The shale minerals of Lower Cambrian Niutitang Formation in Fenggang area of northern Guizhou are mainly composed of quartz，feldspar and clay minerals，followed by carbonate minerals and pyrite. The pore types are mainly organic matter pores，intergranular pores，intragranular pores and micro-cracks，with organic matter pores and clay mineral intergranular pores being the most developed.（2）The average specific surface area of the shale of Niutitang Formation in the study area is 9.536 6 m2/g. The average total pore volume is 0.009 02 cm3/g，the average mesopore volume is 0.007 95 cm3/g，the macropore volume is 0.000 37-0.004 58 cm3/g，with an average value of 0.001 07 cm3/g，and the average pore size is 3.381-5.947 nm. The mesopores are the most developed. The pore volume of shale is mainly contributed by mesopores and macropores，and the specific surface area is mainly contributed by micropores and mesopores. The connectivity between micropores and mesopores and macropores is relatively poor， and the connectivity between mesopores and macropores is good. The pore shapes are mainly ink-bottle shaped， cylindrical shaped，and fracture shaped.（3）TOC，clay minerals and brittle minerals are the main factors controlling the pore structure of shale of Niutitang Formation in the study area. TOC and clay minerals have positive effects on specific surface area，total pore volume，mesopore volume and porosity，while brittle minerals have negative effects on specific surface area，porosity and mesopore volume.
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Characteristics and evolution model of hydrocarbon accumulation of Cambrian Longwangmiao Formation in the north slope of central Sichuan paleo-uplift
LU Keliang, WU Kangjun, LI Zhijun, SUN Yonghe, XU Shaohua, LIANG Feng, LIU Lu, LI Shuang
2024, Vol.36(4): 159–168
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doi: https://doi.org/10.12108/yxyqc.20240414
Based on logging，well log，core analysis and laboratory data，a study was conducted on the hydro‐carbon accumulation conditions，hydrocarbon filling characteristics，and accumulation evolution model of Lower Cambrian Longwangmiao Formation in the north slope of central Sichuan paleo-uplift. The results show that：（1）The natural gas of Lower Cambrian Longwangmiao Formation in the north slope of central Sichuan paleo-uplift has good hydrocarbon accumulation conditions. The source rocks of underlying Qiongzhusi Formation have two hydrocarbon generation centers in the central and western rift troughs of the north slope，with an average TOC of 1.90% and 3.46%，respectively. The organic matter is mainly type Ⅰ kerogen，which can provide sufficient and high-quality hydrocarbon sources. The grain-shoal karst reservoirs developed within Longwangmiao Formation and the dense argillaceous dolomites of the overlying the Gaotai Formation form a dominant reservoir-cap assemblage. The widely developed oil-source faults in the study area can serve as vertically dominant migration channels for efficient hydrocarbon migration.（2）The Longwangmiao Formation in the study area has three stages of hydrocarbon accumulation characteristics：The first stage of filling occurred at the end of Late Triassic（approximately 214-206 Ma），with a large amount of mature oil accumulating to form paleo-oil reservoirs. In the late Early Jurassic（approximately 193-186 Ma），the second stage of filling occurred，characterized by a mixed filling of more oil and less gas. At the end of the Middle Jurassic（approximately 170-164 Ma），the third stage of filling occurred，with a large amount of oil cracked gases filling the reservoir and accumulating to form the current gas reservoir.（3）The hydrocarbon accumulation evolution of Longwangmiao Formation in the study area can be divided into four stages：the early Caledonian to pre Permian stage with a small amount of low mature oil filling，the Permian to Triassic stage with a large amount of mature oil filling to form ancient oil reservoirs，the Middle Jurassic to Cretaceous stage with the destruction of paleo-oil reservoirs to form cracked gas reservoirs，and the Late Cretaceous to present stage with gas reservoir adjustment.
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Numerical simulation of fracture propagation law of in-fracture temporary plugging and diverting fracturing in tight reservoirs
TANG Shukai, GUO Tiankui, WANG Haiyang, CHEN Ming
2024, Vol.36(4): 169–177
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doi: https://doi.org/10.12108/yxyqc.20240415
Based on the theory of damage mechanics，a numerical model of reservoir flow-stress-damage coupling fracture propagation was established，and it was verified by comparing with inddor true triaxial hydraulic fracturing physical simulation experiment results. What’s more，the influences of fracturing fluid viscosity，displacement，horizontal stress difference and reservoir rock heterogeneity on in-fracture temporary plugging and diverting fracturing were discussed. The results show that：（1）The numerical model of reservoir flow-stress- damage coupling fracture propagation is a combination of fluid flow control equation and rock deformation equation to form an overall control equation，and the temporary plugging in the fracture can be simulated by artificially setting high-strength rock physical and mechanical parameters and small reservoir permeability values in a certain area along the initial fracture propagation path.（2）The numbers of branch fractures，area of main fractures，and extension direction of main fracture in numerical simulation of in-fracture temporary plugging and diverting fracturing fracture propagation model are basically consistent with the results of indoor true triaxial hydraulic fracturing physical simulation experiment results. This model can achieve the simulation of matrix fracture and new fracture extension after temporary plugging in fractures，and also has a good simulation effect on the situation of in-fracture temporary plugging and diverting fracturing fracture propagation.（3）The larger the viscosity and displacement of fracturing fluid，the greater the length，reconstruction area and deflection angle of in-fracture temporary plugging and diverting fracturing fracture，and single fractures gradually transition to complex fractures. When the horizontal stress difference is less than 7.5 MPa，the effect of in-fracture temporary plugging and diverting fracturing is better. When the horizontal stress difference is 10-15 MPa，the fracturing effect deteriorates. When the horizontal stress difference is greater than 15 MPa，the fractures hardly deflect. Reservoir heterogeneity can affect the local propagation path of fractures，but has little impact on the overall propagation trend of fractures.
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Water invasion performance and main controlling factors for edge-water gas reservoirs
QIN Zhengshan, HE Yongming, DING Yangyang, LI Baihong, SUN Shuangshuang
2024, Vol.36(4): 178–188
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doi: https://doi.org/10.12108/yxyqc.20240416
Based on classical fractional flow theory and gas-water percolation law，the fractional flow equation for edge-water gas reservoirs considering high-speed non-Darcy flow of gas phase was derived. The characteristic parameters and controlling factors of water invasion performance were analyzed based on the data of multiple water-producing gas wells in an edge-water gas reservoir in Sichuan Basin，and the technical approaches and strategies for delaying water invasion in gas reservoirs were discussed. The results show that：（1）The derived fractional flow equation can determine the overall advancement and breakthrough time of edge water in the reservoir（or gas well）at different development times，and the calculation results are more reliable than that by the traditional Darcy flow model.（2）The water invasion performance of the edge-water gas reservoirs is affected by a combination of multiple factors，the reservoir permeability has the most significant influence，followed by non-Darcy flow coefficient，relative permeability and porosity，while effective thickness，gas supply boundary and water invasion flow rate are less influential.（3）Fully exploiting the development potential of low-permeability and tight reservoirs with relatively uniform physical properties is the key to enhancing the development effectiveness of edge-water gas reservoirs，and formulating a reasonable gas recovery intensity is an important means to actively control and stabilize water.