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Characteristics and exploration potential of shale reservoirs of Permian Longtan Formation in southern Sichuan Basin
YANG Yueming, ZHANG Shaomin, JIN Tao, MING Ying, GUO Ruiying, WANG Xingzhi, HAN Luyuan
2023, Vol.35(1): 1–11
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Discovery of Linshui-Fengdu intra-platform depression of Triassic Jialingjiang Formation in eastern Sichuan Basin and its significance for oil and gas exploration
WEN Huaguo, LUO Bing, ZHONG Kexiu, FENG Qingping, LIU Lei, LIAO Yisha, PENG Cai, CAI Jialan, XU Wenli, ZHU Yixin, HAO Jing, LUO Xin, XU Xu
2023, Vol.35(1): 12–24
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Shale oil reservoir characteristics and controlling factors of Permian Fengcheng Formation in Hashan area,northwestern margin of Junggar Basin
ZENG Zhiping, LIU Zhongquan, ZHAO Leqiang, LI Yanli, WANG Chao, GAO Ping
2023, Vol.35(1): 25–35
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2718 )
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Caprock evaluation and its reservoir control of different accumulation systems in central depression zone of Yinggehai Basin
FAN Caiwei, JIA Ru, LIU Bo, FU Xiaofei, HOU Jingxian, JIN Yejun
2023, Vol.35(1): 36–48
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2630 )
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Geochemical characteristics and sedimentary environment of source rocks of the third member of Paleogene Shahejie Formation in central Laizhouwan Sag,Bohai Sea
DENG Meiling, WANG Ning, LI Xinqi, CHEN Rongtao, LIU Yan, XU Yaohui
2023, Vol.35(1): 49–62
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2583 )
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268
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Architectural elements of fluvial sand bodies of the eighth member of Permian Xiashihezi Formation in eastern Ordos Basin
MA Dongye, CHEN Yuhang, ZHAO Jingzhou, WU Weitao, SONG Ping, CHEN Mengna
2023, Vol.35(1): 63–73
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2522 )
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278
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Tectonic evolution and hydrocarbon accumulation characteristics of Cenozoic in eastern Lufeng 13 subsag, Pearl River Mouth Basin
HE Yong, QIU Xinwei, LEI Yongchang, XIE Shiwen, XIAO Zhangbo, LI Min
2023, Vol.35(1): 74–82
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2550 )
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217
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Diagenesis characteristics of tight sandstone reservoirs with high temperature,overpressure and high CO2 content: A case study of Neogene Meishan-Huangliu Formation in LD10 area,Yinggehai Basin
YANG Kaile, HE Shenglin, YANG Zhaoqiang, WANG Meng, ZHANG Ruixue, REN Shuangpo, ZHAO Xiaobo, YAO Guangqing
2023, Vol.35(1): 83–95
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Prediction and genesis of formation pressure in Dafengshan uplift, Qaidam Basin
YANG Taozheng, LIU Chenglin, TIAN Jixian, LI Pei, RAN Yu, FENG Dehao, LI Guoxiong, WU Yuping
2023, Vol.35(1): 96–107
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2339 )
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Hydrocarbon accumulation characteristics of tight reservoirs of Da'anzhai member of Jurassic Ziliujing Formation in eastern Sichuan Basin
XIE Rui, ZHANG Shangfeng, ZHOU Lin, LIU Haotian, YAO Mingjun, JIANG Xuegui
2023, Vol.35(1): 108–119
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2386 )
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Sedimentary facies characteristics and sedimentary model of thin sand bodies of Lower Cretaceous Shushanhe Formation in Xinhe area, northern Tarim Basin
HE Chunfeng, ZHANG Xiang, TIAN Jingchun, XIA Yongtao, YANG Yanru, CHEN Jie, WANG Xinyu
2023, Vol.35(1): 120–131
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2333 )
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Microscopic pore structure characteristics of the upper member of Oligocene Xiaganchaigou Formation in Yingxi area, Qaidam Basin
XIA Qingsong, LU Jiang, YANG Peng, ZHANG Kun, YANG Chaoyi, NIE Junjie, ZHU Yunfang, LI Lifang
2023, Vol.35(1): 132–144
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2335 )
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Characterization model of oil-water relative permeability curves of sandstone reservoir and its application in numerical simulation
Lü Dongliang, YANG Jian, LIN Liming, ZHANG Kaili, CHEN Yanhu
2023, Vol.35(1): 145–159
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SAGD production performance prediction model based on unsteady heat transfer
DING Chao, WANG Pan, QIN Yadong, LIANG Xiangjin, ZHENG Aiping, LI Ning, XING Xiangrong
2023, Vol.35(1): 160–168
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Characteristics and exploration potential of shale reservoirs of Permian Longtan Formation in southern Sichuan Basin
YANG Yueming, ZHANG Shaomin, JIN Tao, MING Ying, GUO Ruiying, WANG Xingzhi, HAN Luyuan
2023, Vol.35(1): 1–11
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doi: https://doi.org/10.12108/yxyqc.20230101
The Longtan Formation is a new important layer for shale gas exploration and development in Sichuan Basin. The shale reservoirs of Permian Longtan Formation in southern Sichuan Basin was comprehensively studied by means of polarizing microscope identification，field emission scanning electron microscope analysis，X-ray diffraction test，organic carbon content determination，high-pressure mercury injection analysis and on-site analytical gas experiment. The results show that: (1) The Permian Longtan Formation in southern Sichuan Basin is a set of continental meandering river deposits，and shale is developed in fluvial deposits. Its minerals are mainly quartz and clay minerals，with a small amount of carbonate minerals. (2) There are mainly intergranular (marginal) pores and microfractures developed in the shale reservoirs in the study area，intragranular pores and dissolved pores are locally developed，and organic pores are rarely developed，among which microfractures between clay minerals are the most developed. The pore structures are mainly microporous，followed by mesoporous (with pore size of 2-50 nm). The pore size is generally small，with poor sorting，the radius difference between pore and throat is large，and the heterogeneity is strong. (3) In the shale reservoirs in the study area，the gas content in coal rock is the highest，followed by carbonaceous mudstone and mudstone，and the gas content in argillaceous siltstone，siltstone and fine sandstone is the lowest. Compared with the shale reservoir of Longmaxi Formation，the mudstone of Longtan Formation has better porosity and total gas content and poor permeability，and the porosity and total gas content of carbonaceous mudstone are the best. (4) The Permian Longtan Formation in the study area has great exploration potential. The organic matter in the source rocks is mainly type Ⅲ，followed by typeⅡ2. The average value of Ro is about 2.8%，reaching the stage of high maturity. TOC content varies widely， and TOC content in carbonaceous mudstone is generally greater than 15%. (5) Alluvial plain is developed in Permian Longtan Formation in southern Sichuan Basin，being rich in organic shale，with good shale gas formation conditions. The estimated natural gas resources are about 2.4×1012 m3，and the favorable exploration area is mainly located in Gulin-Xuyong area in southern Sichuan Basin.
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Discovery of Linshui-Fengdu intra-platform depression of Triassic Jialingjiang Formation in eastern Sichuan Basin and its significance for oil and gas exploration
WEN Huaguo, LUO Bing, ZHONG Kexiu, FENG Qingping, LIU Lei, LIAO Yisha, PENG Cai, CAI Jialan, XU Wenli, ZHU Yixin, HAO Jing, LUO Xin, XU Xu
2023, Vol.35(1): 12–24
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doi: https://doi.org/10.12108/yxyqc.20230102
The tectono-sedimentary differentiation through geologic history has an important influence on the tectonicsedimentary filling processes of the carbonate strata and the geological conditions for hydrocarbon accumulation in large petroliferous basins. Through the high-density 2D seismic data and logging-drilling data covering the whole area，the uplift and sag patterns and paleogeographic evolution of eastern Sichuan Basin during the depositional period of Triassic Jialingjiang Formation were described in detail. The results show that: (1) Linshui-Fengdu intra-platform depression was identified from the characteristics of seismic section，stratigraphic and lithological combination. Its slope is about 1°-2°，and the slope on the left is greater than the slope on the right. (2) LinshuiFengdu intra-platform depression and other paleogeological units jointly controlled the paleogeographic pattern and tectono-sedimentary differentiation during the depositional period of the second member of Triassic Jianglingjiang Formation (T1 j2). The intra-platform depression controlled the distribution of shoal around it during the early and middle period of T1 j2，and a large area of gypsum lagoons developed in the intra-platform depression during the late period. (3) The Linshui-Fengdu intra-platform depression，with around micro-paleo-geomorphology， controlled the distribution of grain shoals during the early depositional period，and high-quality dolomite reservoirs were more likely to be formed in the high parts of the peripheral structure. The continuous arid and evaporative environment formed a regional cap layer. (4) In general，the T1 j2 has good reservoir-forming geological conditions and is expected to be a strategic exploration area for searching as shoal-facies monoblock gas reservoirs. It is recommended that the high-energy intra-platform shoal facies development belt around the Linshui-Fengdu intraplatform depression should be the key exploration area of Jialingjiang Formation in eastern Sichuan Basin in the future.
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Shale oil reservoir characteristics and controlling factors of Permian Fengcheng Formation in Hashan area,northwestern margin of Junggar Basin
ZENG Zhiping, LIU Zhongquan, ZHAO Leqiang, LI Yanli, WANG Chao, GAO Ping
2023, Vol.35(1): 25–35
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doi: https://doi.org/10.12108/yxyqc.20230103
The Permian Fengcheng Formation in the northwestern margin of Junggar Basin is enriched with shale oil resources，and a major breakthrough has been made in oil and gas exploration in Mahu Sag and Wuxia area. There is certain exploration potential in the adjacent Hasan area. Through rock thin section observation，scanning electron microscope analysis，organic geochemical test，XRD analysis and reservoir physical property analysis， the shale oil reservoir characteristics and controlling factors of Permian Fengcheng Formation in Hashan area were studied. The results show that: (1) The lithologies of shale oil reservoirs of Permian Fengcheng Formation in Hashan area are mainly composed of felsic shale，calcareous shale and mixed shale. The shale could be classified as good to best source rocks. The organic matters are mainly typeⅡ1 and typeⅡ2，and mainly at the immature stage. Some shale samples in the footwall of the overthrusts were involved into early mature stage. (2) The average porosity of the shale oil reservoirs in the study area is 2.32%，belonging to low porosity reservoir. The reservoir space is dominated by inorganic pores and micro-fractures，and the development degree of organic pores is relatively low. (3) The development of shale oil reservoirs of Fengcheng Formation in the study area is mainly controlled by sedimentary facies，diagenesis and tectonic activities. Sedimentary facies not only determines the rock type，but also controls the enrichment of organic matters. Compaction and cementation can play a negative role in reservoir physical properties，and dissolution can greatly improve reservoir physical properties. Micro-fractures formed by tectonic activities can not only provide reservoir spaces for shale oil，but also provide channels for oil and gas migration，thus improving the percolation condition of shale oil reservoirs.
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Caprock evaluation and its reservoir control of different accumulation systems in central depression zone of Yinggehai Basin
FAN Caiwei, JIA Ru, LIU Bo, FU Xiaofei, HOU Jingxian, JIN Yejun
2023, Vol.35(1): 36–48
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doi: https://doi.org/10.12108/yxyqc.20230104
Yinggehai Basin is an important natural gas exploration area in the South China Sea. Based on detailed analysis of typical gas reservoirs and gas-bearing structures of different accumulation systems in the central depression of Yinggehai Basin，the effectiveness and controlling factors of caprocks were evaluated，and the controlling effects of caprocks on natural gas accumulation were analyzed. The results show that: (1) In the ultra-shallow and shallow accumulation systems in the central depression zone of Yinggehai Basin，the sealing of caprocks is controlled by the caprocks，the diapir structure and the faults associated with the activity of the diapir structure. In the middle-deep accumulation system，under the background of abnormally high fluid pressure and the absence of faults，hydraulic sealing of caprocks is the key factor controlling differential enrichment of oil and gas. (2) The critical juxtaposition thickness of the brittle caprocks to maintain the sealing effectiveness is 86-98 m in the ultrashallow and shallow accumulation systems. The effectiveness of the caprocks in the middle-deep accumulation system can be evaluated by the hydraulic fracturing pressure coefficient. When the value is greater than 1，it means that the caprocks have ruptured or have a strong risk of hydraulic fracturing. (3) From the overall view of the central depression，hydraulic fracturing induced by overpressure is the fundamental cause of sealing failure in mid-deep caprocks. Deep natural gas migrates to shallow layer through hydraulic fracturing channel and finally to the ultra-shallow reservoir through the faults. Therefore，under the condition of sufficient gas source，ultra-shallow and shallow gas reservoirs are mainly distributed at the top of the diapir，while middle-deep gas reservoirs are mainly concentrated in the diapir wing and slope areas.
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Geochemical characteristics and sedimentary environment of source rocks of the third member of Paleogene Shahejie Formation in central Laizhouwan Sag,Bohai Sea
DENG Meiling, WANG Ning, LI Xinqi, CHEN Rongtao, LIU Yan, XU Yaohui
2023, Vol.35(1): 49–62
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doi: https://doi.org/10.12108/yxyqc.20230105
The geochemical characteristics and sedimentary environment of the third member of Paleogene Shahejie Formation (E2s3) in central Laizhouwan Sag of Bohai Sea were studied by means of pyrolysis，TOC，GC/MS analysis of saturated hydrocarbons，and major and trace elements analysis of source rock samples. The results show that: (1) The source rocks of E2s3 have different organic matter abundances，they are generally good to high-quality source rocks. The organic matters are mainly type Ⅰ-Ⅱ and in the low mature to mature stage as a whole. (2) According to Pr/nC17-Ph/nC18 plates，C24 tetracyclic terpanes/C26 tricyclic terpanes (C24 TeT/C26 TT)， C27/C29 regular sterane and olliane index，it can be concluded that the organic matters of E2s3 source rocks are derived from mixed inputs of lower aquatic organisms and terrigenous higher plants. (3) CIA，Sr/Ba，Pr/Ph，V (/V+Ni)， U/Th and gammacerane index were used to analyze the paleoenvironment of the source rocks. During the sedimentary period of E2s3，the climate was warm and humid with abundant precipitation. The water environment was fresh-brackish water，accompanied by strong terrigenous input，with high initial productivity，and the sedimentary environment is weak oxidation and weak reduction environment with poor oxygen. The sedimentary environment of E2s3 has little change，and the paleoclimate and water salinity are basically the same. However，terrigenous input and water oxidation conditions gradually increase with the deposition.
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Architectural elements of fluvial sand bodies of the eighth member of Permian Xiashihezi Formation in eastern Ordos Basin
MA Dongye, CHEN Yuhang, ZHAO Jingzhou, WU Weitao, SONG Ping, CHEN Mengna
2023, Vol.35(1): 63–73
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doi: https://doi.org/10.12108/yxyqc.20230106
Based on the description of lithofacies characteristics of fluvial outcrops，the architectural element types，distribution and stacking patterns of fluvial sand bodies of the eighth member of Permian Xiashihezi Formation in eastern Ordos Basin were studied. The results show that: (1) Braided river and meandering river are developed the eighth member of Permian Xiashihezi Formation in eastern Ordos Basin. Eight types of lithofacies were identified，including massive bedding conglomerate (Gm)，trough cross bedding gravelly sandstone (Gst)， trough cross bedding sandstone (St)，tabular cross bedding sandstone (Sp)，parallel bedding sandstone (Sh)， climbing ripple bedding sandstone (Sc)，parallel bedding siltstone (Fh) and massive bedding mudstone (M). (2) Five architectural elements are developed in the study area，including channels (CH)，channel bars (CB)， abandoned channels (ACH)，point bars (PB) and overflow (OF) deposits，and the vertical sedimentary sequences of these architectural elements are obvious differences. CH: Gm-Gst-St-M-St，CB: Gm-Gst-St-Sp，PB: St-Sp-ScSh-M or St-Sp-Sc-M，ACH: Gm-St-Sp-M，OF: Sp-Fh-M. The vertical sedimentary sequences of ACH are similar to that of CH，but featured with smaller grain size and higher mud content. (3) Nine basic combination types of architectural elements are developed in the study area，namely CH-OF，CH-ACH，CH-CB (vertically and laterally)， CH-CH (vertically and laterally)，CB-OF，CB-CB (vertically and laterally)，PB-PB (laterally)，PB-ACH and PB-OF. (4) The types，stacking pattern and distribution of architectural elements of fluvial sand bodies in the study area are affected by the distance of source and hydrodynamic force. The closer to the source，the better the hydrodynamic force，the larger the sand body scale，and the better the connectivity between the sand bodies. In the braided river near the source，the development of sand bodies at the bottom is better than that at the top，and the reservoir capability of point bars is the best. Multi-stage point bars at the bottom of meandering river in the far-source area are well developed and stack laterally with good connectivity.
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Tectonic evolution and hydrocarbon accumulation characteristics of Cenozoic in eastern Lufeng 13 subsag, Pearl River Mouth Basin
HE Yong, QIU Xinwei, LEI Yongchang, XIE Shiwen, XIAO Zhangbo, LI Min
2023, Vol.35(1): 74–82
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doi: https://doi.org/10.12108/yxyqc.20230107
The eastern Lufeng 13 subsag is a key area for oil and gas exploration in the Pearl River Mouth Basin. Combined with regional tectonic background，and based on the fine interpretation of high-quality 3 D seismic data， the structure and structural features of the eastern Lufeng 13 subsag were analyzed，the tectonic evolution of the subsag was restored by using balanced section technology，and the influences of tectonic evolution on trap formation and hydrocarbon accumulation were discussed. The results show that: (1) The Cenozoic tectonic evolution in eastern Lufeng 13 subsag can be divided into three stages: Early-Middle Eocene fault depression，Late Eocene fault depression transition，Oligocene-Quaternary regional thermal subsidence depression. The fault depression stage has a complete fault depression cycle. According to the strength of the fault depression activity，it can be further divided into the initial stage，peak stage and shrinkage stage of the fault depression. The reservoirs were relatively developed in the initial stage and shrinkage stage of the fault depression，and the source rocks were relatively developed in the peak stage of the fault depression. (2) Under the influence of multi-stage tectonic activities，many types of traps were formed in Cenozoic in eastern Lufeng 13 subsag，including drape anticline traps， fault anticline traps，fault block traps，fault nose traps，structural-stratigraphic traps (truncation，overlap) and structural-lithologic traps. So many trap types show great potential for hydrocarbon exploration in this area，in particularly，the Wenchang Formation and Enping Formation，which are deposited in the fault depression stage and fault depression transition stage，have developed a large number of traps of various types. Those traps are close to high-quality source rocks and have favorable conditions for hydrocarbon accumulation，which are the key formations for oil and gas exploration in eastern Lufeng 13 subsag. In plane，the southern gentle slope zone has the most types and numbers of traps，followed by the central uplift zone and low uplift zone，which are the most important zones for hydrocarbon exploration in the study area.
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Diagenesis characteristics of tight sandstone reservoirs with high temperature,overpressure and high CO2 content: A case study of Neogene Meishan-Huangliu Formation in LD10 area,Yinggehai Basin
YANG Kaile, HE Shenglin, YANG Zhaoqiang, WANG Meng, ZHANG Ruixue, REN Shuangpo, ZHAO Xiaobo, YAO Guangqing
2023, Vol.35(1): 83–95
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doi: https://doi.org/10.12108/yxyqc.20230108
By means of thin section identification，scanning electron microscopy，cathodoluminescence，and carbon and oxygen isotope analysis，the diagenesis characteristics and their influence on pores of Neogene MeishanHuangliu Formation under the background of high temperature，overpressure and high CO2 content in LD10 area of Yinggehai Basin were studied. The results show that: (1) The reservoirs of Neogene Meishan-Huangliu Formation in LD10 area of Yinggehai Basin are developed with gravity flow. The lithologies are mainly medium-fine feldspathic lithic quartz sandstones，and the reservoir physical properties are mainly characterized by ultra-low porosity and ultra-low permeability. (2) Compaction，cementation and dissolution are the main diagenesis types in the study area. Overpressure can obviously inhibit the transformation of clay minerals and the secondary enlargement of quartz，which can protect the primary pores to a certain extent. The high-temperature fluid rich in CO2 not only causes the abnormal transformation of clay minerals，but also promotes the dissolution to increase the secondary pores. (3) The diagenetic sequence of the second member of Huangliu Formation is summarized as siderite cementation→secondary enlargement of quartz→chlorite cementation→early stage feldspar dissolution→ kaolinite formation→early stage calcite cementation→early stage dolomite cementation→feldspar dissolution→ calcite dissolution→massive illite formation→late stage iron calcite and iron dolomite formation. (4) In general， compaction reduces the porosity by 45.30%-62.93%，and cementation reduces the porosity by 1.65%-35.01%， while dissolution increases the porosity by 0.72%-8.00%. The sandstone reservoir in the middle and lower part of Huangliu Formation is affected by overpressure and CO2 dissolution，with good physical properties，so high CO2 risk should be considered during drilling.
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Prediction and genesis of formation pressure in Dafengshan uplift, Qaidam Basin
YANG Taozheng, LIU Chenglin, TIAN Jixian, LI Pei, RAN Yu, FENG Dehao, LI Guoxiong, WU Yuping
2023, Vol.35(1): 96–107
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doi: https://doi.org/10.12108/yxyqc.20230109
Overpressure prediction is of great significance to the study of oil and gas accumulation. By means of logging curve combination，cross plot of acoustic velocity and vertical effective stress，cross plot of acoustic velocity and density，and overpressure comprehensive analysis，the overpressure causes of each layer in Dafengshan uplift of Qaidam Basin were analyzed，and the pressure prediction method was improved. The results show that: (1) The overpressure of Xiayoushashan Formation in Dafengshan uplift of Qaidam Basin is caused by uneven compaction and tectonic compression，and the overpressure of Shangganchaigou Formation and upper Xiaganchaigou Formation is caused by uneven compaction，tectonic compression and overpressure transmission. (2) Single methods such as equilibrium depth method or Eaton method cannot be effectively used to predict the formation pressure in the study area. Based on the difference of different overpressure genesis mechanisms，the equilibrium depth method was used to calculate the formation pressure of Xiayoushashan Formation，and the Eaton method was used to calculate the formation pressure of Shangganchaigou Formation and upper Xiaganchaigou Formation，with more accurate results. The error between the calculated pressure and the measured formation pressure in the study area is less than 7.00%，and the average error is 4.30%. (3) Overpressure prediction can provide data support for reservoir description，reserve estimation and safe drilling operation. Overpressure is the driving force of oil and gas migration. It can be used to indicate the direction of oil and gas migration and estimate the distance of oil and gas migration，which has important guiding significance for the study of oil and gas accumulation.
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Hydrocarbon accumulation characteristics of tight reservoirs of Da'anzhai member of Jurassic Ziliujing Formation in eastern Sichuan Basin
XIE Rui, ZHANG Shangfeng, ZHOU Lin, LIU Haotian, YAO Mingjun, JIANG Xuegui
2023, Vol.35(1): 108–119
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doi: https://doi.org/10.12108/yxyqc.20230110
The Da’anzhai member of Jurassic Ziliujing Formation in eastern Sichuan Basin has the typical characteristics of near-source hydrocarbon accumulation. By means of source rock evaluation，fluid inclusion analysis and burial history recovery，the reservoir characteristics and hydrocarbon accumulation of Da’anzhai member of Jurassic Ziliujing Formation in eastern Sichuan were studied. The results show that: (1) The organic matters of Da’anzhai member of Jurassic Ziliujing Formation in eastern Sichuan Basin are mainly type Ⅱ. The measured residual organic carbon mass fraction is 0.67%，the hydrocarbon generation potential is 1.53 mg/g，and the thermal evolution degree of organic matter is 1.1%-1.3%. On the whole，the source rocks of Da’anzhai member have medium to low abundance of organic matters，which is at the peak of hydrocarbon generation. (2) The lithologies of the first submember of Da’anzhai member in the study area are mainly shell limestone and limestone，and the structural fractures are the main reservoir space，followed by dissolved pores (caves) and dissolved micropores developed along the structural fracture. The reservoirs have poor physical properties with ultra-low porosity and ultra-low permeability. (3) There are two stages of crude oil charging and one stage of natural gas charging in the reservoirs of Da’anzhai member in the study area. The two stages of crude oil charging time are about 140 Ma and 25 Ma respectively. The first stage is relatively low maturity crude oil charging，the second stage is relatively high maturity crude oil charging，and the latter is the main charging period. The natural gas charging time is the same as the second stage of crude oil charging，which is mainly associated gas of crude oil.
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Sedimentary facies characteristics and sedimentary model of thin sand bodies of Lower Cretaceous Shushanhe Formation in Xinhe area, northern Tarim Basin
HE Chunfeng, ZHANG Xiang, TIAN Jingchun, XIA Yongtao, YANG Yanru, CHEN Jie, WANG Xinyu
2023, Vol.35(1): 120–131
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229
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doi: https://doi.org/10.12108/yxyqc.20230111
The Lower Cretaceous Shushanhe Formation in Xinhe area is one of the potential fields of lithologic reservoir exploration in northern Tarim Basin. Based on the drilling data from 15 wells and 3D seismic interpretation results，the stratigraphic division of Lower Cretaceous Shushanhe Formation in Xinhe area of northern Tarim Basin was carried out，the sedimentary microfacies characteristics and plane distribution of Shushanhe Formation were studied，and the sedimentary model of thin sand bodies was established. The results show that: (1) Shushanhe Formation in Xinhe area is in conformity contact with the overlying Baxigai Formation and overlying the denuded basement of Shaya uplift，and can be divided into Shu 1 member，Shu 2 member and Shu 3 member. (2) The rock of Shushanhe Formation in the study area is mainly lithic arkose，followed by feldspathic lithic sandstone and arkose. The microfacies of shore shallow lake mud and shore shallow lake sand bar can be identified. (3) Before the deposition of Shushanhe Formation in the study area，three-level paleogeomorphology of uplift， low uplift and depression developed，which controlled the distribution of sedimentary facies. During the sedimentary period of Shu 1 member，the sedimentary range is limited to the depression area. The strata of Shu 2 member overlapped from the depression area to the east and west sides，and the sedimentary area expanded. The sedimentary period of Shu 1 and Shu 2 members presents the distribution characteristics of shore-shallow lake facies belt from the east and west sides to the middle. During the sedimentary period of Shu 3 member，the study area was further transgressive into shallow lake sediments. (4) The thin sand bodies of Shushanhe Formation in the study area are important exploration fields，and their distribution is controlled by paleogeomorphology，lake level change and paleowater depth before sedimentation.
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Microscopic pore structure characteristics of the upper member of Oligocene Xiaganchaigou Formation in Yingxi area, Qaidam Basin
XIA Qingsong, LU Jiang, YANG Peng, ZHANG Kun, YANG Chaoyi, NIE Junjie, ZHU Yunfang, LI Lifang
2023, Vol.35(1): 132–144
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doi: https://doi.org/10.12108/yxyqc.20230112
The upper member of Oligocene Xiaganchaigou Formation (E32) in Yingxi area of Qaidam Basin is a self-generation and self-storage type oil and gas reservoir. By using a series of experimental means such as X-ray diffraction analysis of whole rock mineral content，thin section identification，scanning electron microscope observation，carbon dioxide adsorption，nitrogen adsorption/desorption，high pressure mercury injection，nuclear magnetic resonance and spontaneous absorption，the reservoir characteristics of E32 in Yingxi area were systematically analyzed and the microscopic pore structure characteristics were finely characterized. The results show that: (1) The reservoirs of E32 in Yingxi area are dominated by fine-grained sedimentary rocks. Its mineral composition is mainly carbonate such as dolomite and ankerite，containing terrigenous clasts such as feldspar and quartz，and clay minerals such as illite-montmorillonite mixed-layer and illite. (2) The reservoir rocks in the study area are relatively dense as a whole. The porosity is 1.0%-14.5%，with an average of 4.0%，while the permeability is 0.011-6.146 mD， with an average of 0.125 mD，which is characterized by low porosity and ultra-low permeability. (3) The pore types of the reservoir rocks in the study area are mainly intercrystalline pores，dissolved pores，caves and fractures， and the pores are parallel slit-shaped. (4) The average pore volume of micropores in the study area is 0.005 6 mL/g， accounting for 34.70% of the total pore volume. The average pore volume of mesopores is 0.006 6 mL/g，accounting for 40.84% of the total pore volume. The pore volume of macropores is 0.0039 mL/g，relatively small，accounting for 24.46% of the total pore volume. Therefore，mesopores contribute the most to rock reservoirs，followed by micropore.
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Characterization model of oil-water relative permeability curves of sandstone reservoir and its application in numerical simulation
Lü Dongliang, YANG Jian, LIN Liming, ZHANG Kaili, CHEN Yanhu
2023, Vol.35(1): 145–159
Abstract
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doi: https://doi.org/10.12108/yxyqc.20230113
Taking the sandstone reservoirs of Neogene Guantao Formation in Gudao oilfield of Shengli Oilfield as an example，based on oil-water relative permeability test and geological knowledge，the characterization model of oil-water relative permeability curves was established. The sandstone reservoir model was established by numerical simulation method，and the applicable conditions of model under different rhythms and different development methods and the influence on development results were discussed. The results show that: (1) The correlations of 7 parameters affecting relative permeability curves，such as permeability measured with gas and average pore-throat radius，with endpoints of relative permeability curves and the shape of curves were respectively fitted. Multiple regression method was carried out by using the alternate conditional expectation method，irreducible water saturation calculation model was established based on permeability measured with gas and average pore-throat radius，and residual oil saturation calculation model was established based on permeability variation coefficient and significant parameters. Based on permeability measured with gas，calculation model for relative permeability of oil phase under irreducible water was established. Based on coefficient of variation and significant parameters， calculation model for relative permeability of water phase under residual oil was also established. The absolute errors of the four endpoint characterization models are all less than 0.1. Referring to Honarpour empirical formula， relative permeability curve shape calculation model of oil phase was established based on uniformity coefficient， and relative permeability curve shape calculation model of water phase was established based on permeability variation coefficient and pore-throat ratio. The absolute errors of the two models are less than 1.7，which proves the reliability of models. (2) In the depletion development simulation of sandstone reservoirs，the production performance is mainly controlled by the relative permeability of oil phase. Normalizing curves derived from the model can eliminate the influence of reservoir heterogeneity to a certain extent. In simulated waterflood development，reservoir heterogeneity can exacerbate the impact of water phase relative permeability on production performance. In the simulation，the relative permeability curve of the reservoir that contributes the most to oil production can be closer to the actual production.
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SAGD production performance prediction model based on unsteady heat transfer
DING Chao, WANG Pan, QIN Yadong, LIANG Xiangjin, ZHENG Aiping, LI Ning, XING Xiangrong
2023, Vol.35(1): 160–168
Abstract
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doi: https://doi.org/10.12108/yxyqc.20230114
According to the theories of heat transfer and thermal recovery，the SAGD (steam-assisted gravity drainage) unsteady heat transfer model and the analytical solutions of key development indexes were derived， which were taken into account for boundary effect. The rapid prediction of development indexes was realized by using the program design method. The results show that: (1) The existing unsteady heat transfer models have limitations on the temperature assumption of the outer boundary of heat transfer. According to the principle of energy conservation，the outer boundary condition of heat transfer was modified，and the analytical relationship between the heat transfer depth and the accumulated heat transfer was established，which can be used to quantitatively calculate the heat loss of the overburden and underburden. (2) On the basis of Butler’s classical SAGD production model，the analytical models of water production，oil-steam ratio and steam heat utilization ratio in the steam chamber rising stage，lateral expansion stage and downward expansion stage were derived respectively，which can realize the rapid prediction of key indicators in the specific development stage or the whole life cycle of SAGD. (3) By comparing with the actual production indexes of the well group in 6.4 years，the coincidence rates of predicted oilsteam ratio and predicted water-cut are above 95%，which confirms the reliability of the analytical model and the program design. (4) According to the reservoir parameters of Zhong 32 well area in Fengcheng oilfield of Junggar Basin，the predicted and analyzed SAGD steam heat utilization rate and key development indicators under different oil layer thickness conditions show that when the steam heat utilization ratio is greater than 35% and the oilsteam ratio is greater than 0.15，the corresponding oil layer thickness should be greater than 12 m.