- Article List
- Full Abstracts
-
Origins and accumulation characteristics of large-scale generation of natural hydrogen
YIN Lu, LI Bo, QI Wen, SUN Dong, YUE Xingfu, MA Hui
2024, Vol.36(6): 1–11
Abstract
(
186 )
HTML
(0 KB)
PDFEN
(10122 KB)
(
270
)
-
Prediction of shale formation pore pressure based on Zebra Optimization Algorithm-optimized support vector regression
ZHAO Jun, LI Yong, WEN Xiaofeng, XU Wenyuan, JIAO Shixiang
2024, Vol.36(6): 12–22
Abstract
(
100 )
HTML
(0 KB)
PDFEN
(3003 KB)
(
174
)
-
Intelligent comprehensive prediction technology of coalbed methane “sweet spot”reservoir of Jurassic Xishanyao Formation in Baijiahai uplift，Junggar Basin
LI Daoqing, CHEN Yongbo, YANG Dong, LI Xiao, SU Hang, ZHOU Junfeng, QIU Tingcong, SHI Xiaoqian
2024, Vol.36(6): 23–35
Abstract
(
133 )
HTML
(0 KB)
PDFEN
(19211 KB)
(
189
)
-
Analysis of deformation mechanism of ultra thick gypsum salt rock and its significance for oil and gas reservoir formation：A case study of the Jurassic gypsum salt layers in theAgayry region，eastern right bank of theAmu Darya River
ZHANG Peijun, XIE Mingxian, LUO Min, ZHANG Liangjie, CHEN Renjin, ZHANG Wenqi, YUE Xingfu, LEI Ming
2024, Vol.36(6): 36–44
Abstract
(
107 )
HTML
(0 KB)
PDFEN
(34485 KB)
(
183
)
-
Reservoir forming conditions and exploration prospect of Jurassic coalbed methane encircling Dongdaohaizi sag，Junggar Basin
YU Qixiang, LUO Yu, DUAN Tiejun, LI Yong, SONG Zaichao, WEI Qingliang
2024, Vol.36(6): 45–55
Abstract
(
97 )
HTML
(0 KB)
PDFEN
(14530 KB)
(
138
)
-
Application of ray-path elastic impedance inversion in carbonate gas reservoir prediction of the right bank of Amu Darya River
ZHANG Tianze, WANG Hongjun, ZHANG Liangjie, ZHANG Wenqi, XIE Mingxian, LEI Ming, GUO Qiang, ZHANG Xuerui
2024, Vol.36(6): 56–65
Abstract
(
92 )
HTML
(0 KB)
PDFEN
(16075 KB)
(
138
)
-
Favorable exploration area and formation condition of bedrock reservoir in the of central paleo-uplift，northern Songliao Basin
RAN Yixuan, WANG Jian, ZHANG Yi
2024, Vol.36(6): 66–76
Abstract
(
88 )
HTML
(0 KB)
PDFEN
(7010 KB)
(
118
)
-
Palaeozoic gas reservoir-forming conditions and main controlling factors in Xunyi area，southern Ordos Basin
Guan Yunwen, Su Siyu, Pu Renhai, Wang Qichao, Yan Sujie, Zhang Zhongpei, Chen Shuo, Liang Dongge
2024, Vol.36(6): 77–88
Abstract
(
138 )
HTML
(0 KB)
PDFEN
(68358 KB)
(
170
)
-
Stratigraphic division of astronomical cycle in early-middle Jurassic Shuixigou Group in the Shengbei subsag of Tuha Basin
GOU Honguang, LIN Tong, FANG Qiang, ZHANG Hua, LI Shan, CHENG Yi, You Fan
2024, Vol.36(6): 89–97
Abstract
(
102 )
HTML
(1 KB)
PDFEN
( KB)
(
117
)
-
Main controlling factors for the high yield of tight oil in the Jurassic Da’anzhai Section in the western area of Gongshanmiao, Sichuan Basin
YAN Xueying, SANG Qin, JIANG Yuqiang, FANG Rui, ZHOU Yadong, LIU Xue, LI Shun, YUAN Yongliang
2024, Vol.36(6): 98–109
Abstract
(
110 )
HTML
(0 KB)
PDFEN
(57590 KB)
(
160
)
-
Geochemical characteristics of source rocks and evaluation of shale oil “sweet spot”of Permian Fengcheng Formation in Mahu Sag
BAI Yubin, LI Mengyao, ZHU Tao, ZHAO Jingzhou, REN Haijiao, WU Weitao, WU Heyuan
2024, Vol.36(6): 110–121
Abstract
(
136 )
HTML
(0 KB)
PDFEN
(6349 KB)
(
115
)
-
Characteristics of Cretaceous source rocks and their controlling effect on hydrocarbon accumulation in Dehui Fault Depression，Songliao Basin
QU Weihua, TIAN Ye, DONG Changchun, GUO Xiaobo, LI Lili, LIN Siya, XUE Song, YANG Shihe
2024, Vol.36(6): 122–134
Abstract
(
96 )
HTML
(0 KB)
PDFEN
(5824 KB)
(
115
)
-
Characteristics and favorable zone distribution of tuff reservoirt of Cretaceous in A’nan sag，Erlian Basin
XIAO Boya
2024, Vol.36(6): 135–148
Abstract
(
79 )
HTML
(0 KB)
PDFEN
(11631 KB)
(
116
)
-
Geochemical characteristics of Permian condensate oil and gas and phase types in southwest of Mahu Sag
WANG Yifeng, TIAN Jixian, LI Jian, QIAO Tong, LIU Chenglin, ZHANG Jingkun, SHA Wei, SHEN Xiaoshuang
2024, Vol.36(6): 149–159
Abstract
(
126 )
HTML
(0 KB)
PDFEN
(2098 KB)
(
95
)
-
Heterogeneity of soluble organic matter in shale and occurrence state of shale oil under nanoconfinement
HONG Zhibin, WU Jia, FANG Peng, YU Jinyang, WU Zhengyu, YU Jiaqi
2024, Vol.36(6): 160–168
Abstract
(
86 )
HTML
(0 KB)
PDFEN
(18787 KB)
(
141
)
-
Characteristics and genetic mechanism of condensate oil and gas of the Jurassic Sangonghe Formation in western well Pen-1 sag，Junggar Basin
QIAO Tong, LIU Chenglin, YANG Haibo, WANG Yifeng, LI Jian, TIAN Jixian, HAN Yang, ZHANG Jingkun
2024, Vol.36(6): 169–180
Abstract
(
102 )
HTML
(0 KB)
PDFEN
(4820 KB)
(
119
)
-
Simulation of microscopic seepage characteristics of CO2 immiscible flooding under the effect of diffusion and adsorption
CUI Chuanzhi, LI Jing, WU Zhongwei
2024, Vol.36(6): 181–188
Abstract
(
126 )
HTML
(0 KB)
PDFEN
(13966 KB)
(
170
)
-
Origins and accumulation characteristics of large-scale generation of natural hydrogen
YIN Lu, LI Bo, QI Wen, SUN Dong, YUE Xingfu, MA Hui
2024, Vol.36(6): 1–11
Abstract
(
186 )
PDF (10122 KB) (
270
)
doi: https://doi.org/10.12108/yxyqc.20240601
At present，the estimation of global natural hydrogen resources is enormous，and the understanding of its formation mechanism and enrichment rules is helpful for searching for large-scale accumulation areas of natural hydrogen. Through the statistical analysis of typical natural hydrogen displays both domestically and internation ally，the origin types of large-scale accumulation of global natural hydrogen gas were summarized，and the distri bution and accumulation characteristics of natural hydrogen gas reservoirs were analyzed. The results show that： （1）The origin of natural hydrogen is complex，mainly including water-rock reactions，degassing of deep-seated hydrogen from the mantle，water radiolysis，rock fragmentation，decomposition of organic matter，and biological activity. Among them，hydrogen generation through water-rock reactions and degassing of deep-seated hydrogen from the mantle are commonly occurring in nature，and widely present in various geological environments，with high hydrogen generation rates and large amounts. Therefore，they are the two most important origin types for the large-scale generation of natural hydrogen.（2）The natural hydrogen gas reservoirs are mainly developed in three geological backgrounds：plate subduction zones，pre-Cambrian iron-rich strata development areas，and rift tectonic systems.（3）The sealing conditions of natural hydrogen reservoirs are affacted by multiple factors，including not only the sealing ability of the cap rocks，but also the changes in the mechanical properties of the cap rocks caused by the active physical and chemical properties of hydrogen，which affect its brittleness-toughness and form fractures，resulting in the escape of hydrogen.（4）Metabolic activities of underground microorganisms by hydrogen，and hydrocarbon generation in the middle and deep layers are not conducive to the large-scale accumu lation of hydrogen. Therefore，when searching for favorable areas for natural hydrogen generation，areas where hydrogen is consumed in large quantities should be avoided.（5）Due to factors such as the short time of natural hydrogen generation and its diffusion，the accumulation of natural hydrogen shows dynamic characteristics. When hydrogen generation and escape are in a dynamic equilibrium，it can be enriched to accumulate. Groundwater is a necessary condition for hydrogen generation through water-rock reactions，and many natural hydrogen reservoirs discovered abroad are distributed in areas with good groundwater circulation.
-
Prediction of shale formation pore pressure based on Zebra Optimization Algorithm-optimized support vector regression
ZHAO Jun, LI Yong, WEN Xiaofeng, XU Wenyuan, JIAO Shixiang
2024, Vol.36(6): 12–22
Abstract
(
100 )
PDF (3003 KB) (
174
)
doi: https://doi.org/10.12108/yxyqc.20240602
To address the complexity and heterogeneity of the pore structure of seventh member of Triassic Yanchang Formation（Chang 7 member）in Longdong area，a method based on the Zebra Optimization Algorithm-optimized Support Vector Regression（ZOA-SVR）model was proposed. This method utilizes formation pressure test data and conventional well logging curves. It was applied in actual wells，and compared with other machine learning models，as well as conventional methods for predicting formation pressure. The results show that：（1）The ZOA-SVR model uses actual formation pressure data as target variables，selecting seven input feature parameter，such as depth， sonic transit time，density，compensated neutron，natural gamma，deep resistivity，and clay content，associated with shale formation pressure data correlation above 0.7 in the study area. The model was trained with 40 samples， validated with 5-fold cross-validation，and optimized with 10 initial Zebra populations and a maximum of 70 iterations. After optimizing penalty factors and kernel parameters，the model achieved a fit indicator R2 of 0.942. Predicted formation pressure data had absolute errors below 1 MPa on both training and test sets，with an aver age relative error of 2.42% compared to measured data.（2）The ZOA-SVR model demonstrated significant advantages in predicting of Chang 7 Member formation pressure in the study area compared to models based on Particle Swarm Optimization，Grey Wolf Algorithm，and Ant Colony Algorithm. It shows a better parameter adjustment and optimization capabilities，with coefficient of determination increases of 0.209，0.327，and 0.142 respectively. It also exhibited higher accuracy in pressure prediction compared to Equivalent Depth Method，Eaton Method，and Effective Stress Method，reducing relative errors by 32.53%，15.31%，and 5.91% respectively. （3）Application of the ZOA-SVR model in actual wells indicated stable vertical distribution of chang 7 Member formation pressure in the study area. Pressure in mud shale sections is higher than the sandstone sections，with pressure coefficients mainly range from 0.80 to 0.90，indicating an overall abnormally low pressure environment consistent with actual formation conditions.
-
Intelligent comprehensive prediction technology of coalbed methane “sweet spot”reservoir of Jurassic Xishanyao Formation in Baijiahai uplift，Junggar Basin
LI Daoqing, CHEN Yongbo, YANG Dong, LI Xiao, SU Hang, ZHOU Junfeng, QIU Tingcong, SHI Xiaoqian
2024, Vol.36(6): 23–35
Abstract
(
133 )
PDF (19211 KB) (
189
)
doi: https://doi.org/10.12108/yxyqc.20240603
In order to solve the problems of small coal thickness，small vertical fault distance of gas source fault，low signal-to-noise ratio of seismic data and difficult to predict the sweet spot reservoir of coal，rock and gas in Baijiahai uplift，Junggar basin. A“five-step method”is proposed，which is controlled stepwise. The re sults show that：（1）“Five-step”comprehensive technology provides a powerful technical means for coalbed methane“sweet spot”reservoir prediction，The specific method is to improve the signal-to-noise ratio and resolu tion of CRP gathers using construction edge preserving denoising and harmonic high-frequency recovery processing techniques；The combination of tuning thickness method and frequency division intelligent inversion method， the thickness distribution range of coalbed section and plane is quantitatively predicted；The deep learning intel ligent fracture detection technology was used to predict the fracture profile and plane distribution characteristics of gas source；Analysis of AVO characteristics with different gas saturation based on fluid replacement of coal and rock，the gas saturation is used to predict the gas distribution range in the study area；The“sweet spot”reser voir is located in the superposition of broken nose（or fault block），large coal rock thickness，gas source fracture and high gas saturation.（2）The“sweet spot”is mainly distributed in the fault nose or block trap on the north and south sides of the strike-slip fault in the northern part of the work area，A total of 31 coalbed methane“sweet spot”regions have developed，with a cumulative area of 231.9 km2，The exploration potential of the five“sweet spot”reservoirs on the north side of the strike-slip fault is greater.（3）The coincidence rate between the test index of the vertical well deployed by the research results and the real drilling results is 92%. At the same time， the trajectory of the horizontal well can be optimized and dynamically monitored to improve the productivity of a single well.
-
Analysis of deformation mechanism of ultra thick gypsum salt rock and its significance for oil and gas reservoir formation：A case study of the Jurassic gypsum salt layers in theAgayry region，eastern right bank of theAmu Darya River
ZHANG Peijun, XIE Mingxian, LUO Min, ZHANG Liangjie, CHEN Renjin, ZHANG Wenqi, YUE Xingfu, LEI Ming
2024, Vol.36(6): 36–44
Abstract
(
107 )
PDF (34485 KB) (
183
)
doi: https://doi.org/10.12108/yxyqc.20240604
The right bank of the Amu Darya River in Turkmenistan is characterized by the development of a sig nificant gypsums and salts of the upper Jurassic Kimmeridgian stage. It has important influence on the hydrocarbon enrichment and accumulation. By comprehensively utilizing data of drilling，core analysis and seismic，typi cal tectonic styles of different strata of the Jurassic gypsum salt layers in the Agayry region，eastern right bank of the Amu Darya River were identified by analyzing the geomorphology of the profile and portraying the seismic crossover frequency attributes. At the same time，the deformation mechanism of the gypsum salt rock and adja cent strata in the context of the regional tectonic movement was explored，and then the ancient structures of the key reservoir formation period were restored，further investigating the role of tectonics in controlling oil and gas transportation and reservoir formation in different periods. The results show that：（1）The upper and overlying strata of the upper salt layer of Jurassic gypsum salt layers in the Agayry region develop detachment folds，while the lower part develops a small amount of large salt pillow structures. The overall deformation degree of the middle gypsum lower salt layer lower gypsum layer is relatively low. Three types of small salt pillow structures and salt necking are developed within the lower salt layer，and typical reef/hill beach bodies can be identified be tween the salt pillow structures.（2）The function of tectonic compression stress and gravity decollement is the main driving forces for the formation of salt layer deformation. Based on the four key factors of "two major tec tonic movements，pre-existing landforms/structures，multi-layer differentiated deformation plastic strata，and longitudinal and transverse composite superimposed deformation”，a multi-layer superimposed complex struc tural deformation model was established.（3）The flow thickening of salt layers and backfilling method was used to restore the ancient structures of before the deposition of salt layers and during the peak period of hydrocarbon generation at the end of the Early Cretaceous in the study area. By integrating the history of hydrocarbon generation and expulsion，structural development，and gas well production，it was clarified that the ancient structures restored based on gypsum salt rock deformation are important factors for high natural gas accumulation and production， with characteristics of“continuous natural gas injection and multi-stage dynamic reservoir formation”. The inherited development areas of ancient and modern structures are the most favorable areas for natural gas enrichment.
-
Reservoir forming conditions and exploration prospect of Jurassic coalbed methane encircling Dongdaohaizi sag，Junggar Basin
YU Qixiang, LUO Yu, DUAN Tiejun, LI Yong, SONG Zaichao, WEI Qingliang
2024, Vol.36(6): 45–55
Abstract
(
97 )
PDF (14530 KB) (
138
)
doi: https://doi.org/10.12108/yxyqc.20240605
A series of studies，such as coal seam connecting well profiles，logging-seismic calibration，seismic profile interpretation ，analysis of coal seam logging data，have been carried out to clarify the exploration direc tion of coalbed methane in the area of Encircling Dongdaohaizi sag. The results show that：（1）The Jurassic Xishanyao Formation and Badaowan Formation in this area developed coal seams with thick，widely distribu tion. Xishanyao Formation develops 2-3 layers of coal seams，with a cumulative maximum thickness of 20 m， Badaowan Formation develops 2-4 layers of coal seams，with a cumulative maximum thickness of 29 m. Analy sis of coal rock gas content and abnormal logging gas shows that good gas bearing property.（2）The analysis of the main controlling factors for coalbed methane reservoir formation indicates that the middle and lower Jurassic coal measure source rocks in the sag good，reaching a medium to good e source rock level，with Ro value rang ing from 0.6% to 0.8%. It has good ability to generate hydrocarbon gas. In addition，based on the analysis results of natural gas carbon isotopes，coalbed methane also can come from deep highly mature humic source rock. （3）Xishanyao Formation coal rock is a medium-low porosity and low permeability reservoir，with value of po rosity range from 7.0% to 20.8%，value of permeability range from 0.32 mD to 8.67 mD. Badaowan Formation coal rock is a low porosity and medium-low permeability reservoir，with value of porosity range from 5.6% to 7.8%，value of permeability range from 2.3 mD to13.83 mD. The coal seam is sandwiched between mudstones， and the regional mudstone cover is widely distributed above the coal seam，due to a good sealing conditions in this area.（4）There are two modes of coalbed methane enrichment and accumulation in this area：The model of coalbed methane enrichment and accumulation in the source area of the sag and a model of enriched external gas accumulation in the deep bulge area. It is considered that there are greater exploration potential of encircling Dongdaohaizi sag，especially，exploration in slope area of Dongdaohaizi sag northeastern direction and Dongdaohaizi sag northern slope to Dinan uplift.
-
Application of ray-path elastic impedance inversion in carbonate gas reservoir prediction of the right bank of Amu Darya River
ZHANG Tianze, WANG Hongjun, ZHANG Liangjie, ZHANG Wenqi, XIE Mingxian, LEI Ming, GUO Qiang, ZHANG Xuerui
2024, Vol.36(6): 56–65
Abstract
(
92 )
PDF (16075 KB) (
138
)
doi: https://doi.org/10.12108/yxyqc.20240606
The reflection energy of middle-upper Jurassic Karlov-Oxfordian carbonate reservoir in the Agayry gas field on the right bank of the Amu Darya River is weak，and the signal-to-noise ratio of seismic data is low. Based on the analysis of reservoir characteristics and rock physics，the gas-bearing reservoir is predicted by prestack gather conditioning，well-seismic joint low-frequency impedance modeling，pre-stack ray domain elastic impedance inversion. The results show that：（1）The Calllovian-Oxfordian reservoirs in the middle and upper Jurassic of the Agayry gas field are mainly gentle slope carbonate rocks in the front edge of the platform. The lithology is mainly sandy limestone and bioclastic limestone. The reservoir space is dominated by pore-fracture type，which has the characteristics of low porosity，low permeability and strong heterogeneity. The results of rock physics analysis show that the effective gas-bearing reservoirs are mainly characterized by low longitudinal wave impedance，low shear modulus and low bulk modulus，and the shear modulus is the most sensitive to gasbearing reservoirs.（2）The pre-stack gathers are processed by means of prediction elimination denoising，singu lar value decomposition denoising and spectral balance energy compensation，which can effectively remove highfrequency and random noise such as abnormal amplitude，improve the effective signal strength and enhance the AVO characteristics at far offset. The well-seismic joint modeling method solves the problem of multi-solution inversion caused by the lack of low-frequency information of seismic data by introducing low-frequency layer velocity，which improves the inversion accuracy and effectively characterizes the lateral change of reservoir. The pre-stack ray domain elastic impedance inversion method has a good application effect in the study area. The P-wave and S-wave impedance inversion results show high resolution in both vertical and horizontal directions. The predicted gas-bearing reservoir thickness is more than 85% consistent with the results of logging interpreta tion. At the same time，the inversion indicated that lateral continuity of the gas layer is poor，which is consistent of the sedimentary characteristics of the gentle slope beach.（3）The carbonate reservoirs in the study area are favorable areas of exploration and development potential. There are many obvious gas shows in the undrilled areas in the east and southwest. The gas-bearing display of the upper Gap-XVhp is better.
-
Favorable exploration area and formation condition of bedrock reservoir in the of central paleo-uplift，northern Songliao Basin
RAN Yixuan, WANG Jian, ZHANG Yi
2024, Vol.36(6): 66–76
Abstract
(
88 )
PDF (7010 KB) (
118
)
doi: https://doi.org/10.12108/yxyqc.20240607
The favorable area of bedrock gas exploration in the central paleo-uplift of Songliao Basin was se lected on the basis of genesis and formation condition analysis，in order to find the gas accumulation areas. The result shows that：（1）The gas composition and genesis in the central paleo-uplift of northern Songliao Basin is similar to Xujiaweizi fault depression. They are all coal-type gas formed in high and over mature stage，indicate that the gas in the central paleo-uplift is come from the Xujiaweizi fault depression.（2）The union of formation condition such as favorable source rock，favorable reservoir，transport system and favorable cap are the key fac tors for bedrock reservoir. The TOC of source rocks of Shahezi Formation mudstone and coal is 4.33% and 32.56%，which are in mature to high state. The hydrocarbon generation intensity in Songzhan sag and Xuxi sag is greater than 180×108 m3/km2，which is main gas source for the bedrock reservoirs. The pore layer on top of weathering crust and fracture layer in bottom of inner bedrock are the favorable reservoirs，which are formed by "weathering + fracture"，with a porosity of 4.3% and 1.3%，and permeability of 0.45 mD and 6.3 mD. There are “S”type，“T”type and“fault- fracture”transport channels coupled by the crust of weathering，fault and frac ture，promote the natural gas migration in lateral. The mudstone of Denglouku Formation formed early than gas migration，which is characteristic by great thickness and high breakthrough pressure，due to the preservation of gas reservoirs.（3）Central paleo-uplift can be divided to three favorable exploration areas. The gas in Wangjiatun and Changde bulge are mainly crust of weathering，with a“S”type and“T”type transport channel. The gas are control by the union of transport channel and preservation condition. The gas in Zhaozhou bulge are bedrock gas reservoir，with a transport channel of“fault- fracture”body，which is under controlled by reservoir thickness， quality and trapes.
-
Palaeozoic gas reservoir-forming conditions and main controlling factors in Xunyi area，southern Ordos Basin
Guan Yunwen, Su Siyu, Pu Renhai, Wang Qichao, Yan Sujie, Zhang Zhongpei, Chen Shuo, Liang Dongge
2024, Vol.36(6): 77–88
Abstract
(
138 )
PDF (68358 KB) (
170
)
doi: https://doi.org/10.12108/yxyqc.20240608
The exploration and development prospects of the Paleozoic area in the southern Ordos Basin are promising，but the exploration results have been unsatisfactory. Based on the latest core analysis，data of logging and 2D/3D seismic，a comprehensive evaluation was conducted for the Palaeozoic of Xunyi area. This evaluation focused on four aspects：gas source conditions，reservoir quality，source-reservoir configuration，and fracture conductivity. The results show that：（1）In the Xunyi area，potential hydrocarbon source rock types have been identified in the Taiyuan-Shanxi formations：black coal rock，black carbonaceous mudstone，dark gray，and gray mudstone. The organic matter types are all Type Ⅲ，with a vitrinite reflectance（Ro）ranging from 1.8% to 2.5%，indicating a high level of thermal maturity. The black coal rock and carbonaceous mudstone exhibit better hydrocarbon generation potential compared to the dark gray and gray mudstones.（2）The reservoirs are charac terized by ultra-low porosity and ultra-low permeability. The upper Paleozoic Shanxi Formation and He 1 mem ber consist of clastic rock reservoirs，with lithic sandstones accounting for 79%，and matrix content averaging 29%. The pore types are mainly intergranular and secondary dissolution pores，with plane porosity lower than 3%. The He 1 member is characterized by strong cementation and weak dissolution facies，while the Shanxi For mation exhibits strong compaction and matrix-rich infill facies. The high-quality carbonate reservoirs of the lower Paleozoic Majiagou Formation are dominated by sandy dolomite，with storage space mainly comprising dissolu tion pores，intercrystalline pores，and fractures. （3）The Paleozoic source-reservoir configurations include “lower-generation upper-storage”，“upper-generation lower-storage”，and“adjacent lateral-storage”configura tions. Among these，the adjacent lateral-storage configuration is the favorable source-reservoir combination for the lower Paleozoic Majiagou Formation. The Xunyi area experienced three phases of fault development：Paleo zoic，Triassic，and late Jurassic，with the late Jurassic faults providing good vertical fluid migration pathways. （4）The lower Paleozoic gas reservoirs are controlled by the pre-Carboniferous paleogeomorphology. The area adjacent to the eastern side of the deeply eroded paleotroughs is a favorable zone for Lower Paleozoic hydrocar bon accumulation. The upper Paleozoic gas reservoirs are controlled by effective drainage systems. Poor reservoir properties and the lack of open source-conducting faults in the northern part of the study area are the main rea sons for the unfavorable results in the upper Paleozoic.
-
Stratigraphic division of astronomical cycle in early-middle Jurassic Shuixigou Group in the Shengbei subsag of Tuha Basin
GOU Honguang, LIN Tong, FANG Qiang, ZHANG Hua, LI Shan, CHENG Yi, You Fan
2024, Vol.36(6): 89–97
Abstract
(
102 )
PDF (5267 KB) (
117
)
doi: https://doi.org/10.12108/yxyqc.20240609
The natural gamma-ray（GR）logging data of the early-middle Jurassic Shuixigou Group from QinTan 1 borehole in Shengbei subsag，Tuha basin，was selected to analyze cyclostratigraphy and simulate sedimentary noise for the identification of stratigraphic Milankovitch signals and determination of the Earth’s orbital cycle’s forcing the lake level variations within the Tuha Basin. The stratigraphic division of Shuixigou Group was ana lyzed. The results show that：（1）The sedimentary cycles of 12.8～51.1 m，3～11.9 m，1.1～3.6 m，and 1.3～ 2.4 m were identified in the GR curves of the Early-Middle Jurassic Shuixigou Group in the Shengbei subsag of Tuha Basin，with a ratio of 21∶5∶1.5∶1，and the sedimentary rates of the Shuixigou Group are estimated as 3.6～ 11.7 cm·ka-1 through astronomical calibration and correlation coefficient.（2）The sedimentary records of the Shuixigou Group were forced by the Milankovitch cycles，as evidenced by the presence of 405 ka long eccentricity， 99～131 ka short eccentricity，32.6～35.0 ka obliquity，and 20.0～24.8 ka precession cycles during the Middle and Early Jurassic in Tuha basin. The durations of Badaowan Formation（not drilled through），Sangonghe Formation and Xishanyao Formation in Qintan 1 borehole are 3.0 ±0.1 Ma，4.1 ±0.1 Ma and 9.0 ±0.1 Ma， respectively.（3）The fluctuation of lake level forced by the Earth’s orbital cycles of terrestrial lake basins，the simulation of lake level change by sedimentary noise confirms that the ultra-long period of ～1.5 Ma forced the lake level change of the Shuixigou Group in Taibei sag.
-
Main controlling factors for the high yield of tight oil in the Jurassic Da’anzhai Section in the western area of Gongshanmiao, Sichuan Basin
YAN Xueying, SANG Qin, JIANG Yuqiang, FANG Rui, ZHOU Yadong, LIU Xue, LI Shun, YUAN Yongliang
2024, Vol.36(6): 98–109
Abstract
(
110 )
PDF (57590 KB) (
160
)
doi: https://doi.org/10.12108/yxyqc.20240610
On the basis of the understanding of the characteristics of tight limestone reservoirs in the Da’anzhai Formation in the western area of Gongshanmiao of Sichuan Basin，the development scale of the fracture system was identified and graded by using the methods of thin section identification，logging response，and SMI And the main controlling factors of tight oil and high yield in the Da’anzhai Member were studied. The results show that：（1）The limestone of the Da’anzhai section is divided into two types of reservoirs：thick-bedded limestone and thin-bedded limestone. The limestone reservoir has an average porosity of 1.2% and an average permeability of 0.05×10-3 μm2，which is a very low porosity and low permeability reservoir，and dissolution is an important factor in the formation of reservoir properties，and the reservoir space is mainly secondary dissolved pores and micro-fractures.（2）According to the size of the fault，the fault layer and the fault distance on the plane，the fault is divided into primary，secondary and tertiary. Among them，the Da’anzhai section is mainly affected by the primary and secondary faults，the fractures associated with faults can effectively improve the physical proper ties of the reservoir.（3）It is concluded that favorable facis development and t relationship of fault-reservoir con figuration are the control factor to determine the high yield of the reservoir. There are two high-yield models： “thin limestone first-level fracture”and“thick limestone first-level/second-level fracture”.
-
Geochemical characteristics of source rocks and evaluation of shale oil “sweet spot”of Permian Fengcheng Formation in Mahu Sag
BAI Yubin, LI Mengyao, ZHU Tao, ZHAO Jingzhou, REN Haijiao, WU Weitao, WU Heyuan
2024, Vol.36(6): 110–121
Abstract
(
136 )
PDF (6349 KB) (
115
)
doi: https://doi.org/10.12108/yxyqc.20240611
The source rock characteristics of the Permian Fengcheng Formation in Mahu Sag were defined based on a variety of petrographic and organic geochemical data，such as rock slices，total organic carbon（TOC）， rock-eval pyrolysis，chloroform bitumen“A”and vitrinite reflectance（Ro）. The evaluation standard of shale oil “sweet spot”was established，and the distribution characteristics of“sweet spot”in the study area were systematically described by taking typical wells as examples. The results show that：（1）The source rocks of Permian Fengcheng Formation in Mahu Sag are mainly composed of quartz，feldspar and dolomite，followed by calcite and clay minerals. The rock types include calcareous mudstone，sandy mudstone，dolomitic mudstone and mud stone.（2）The abundance of organic matter in source rocks with different lithologies is different，and TOC is 0.75% on average. The organic matter type is mainly type Ⅱ，which is the main source of oil generation，fol lowed by type Ⅰ and a small amount of type Ⅲ. It is in the low maturity to mature evolution stage，and dominated by medium to very high-quality source rocks.（3）TOC，chloroform bitumen“A”，free hydrocarbon S1 and Ro were selected as evluation parameters for shale oil“sweet spot”and divided into four resource types：enriched， medium enriched，low efficiency and ineffective.（4）The evaluation results of shale oil“sweet spot”in typical well Maye 1 show that the shale oil exploration potential is the best in the layers with high TOC，chloroform bitu men“A”，S1，and oil saturation index（OSI）. In addition，shale oil also has exploration potential in the relatively organic-poor interval with high S1.
-
Characteristics of Cretaceous source rocks and their controlling effect on hydrocarbon accumulation in Dehui Fault Depression，Songliao Basin
QU Weihua, TIAN Ye, DONG Changchun, GUO Xiaobo, LI Lili, LIN Siya, XUE Song, YANG Shihe
2024, Vol.36(6): 122–134
Abstract
(
96 )
PDF (5824 KB) (
115
)
doi: https://doi.org/10.12108/yxyqc.20240612
Based on experimental analysis of source rock，gas and reservoir fluid inclusions，we systematically study the geochemical properties，development environment，origin and source of natural gas，hydrocarbon accumulation period and reservoir control function of the Cretaceous source rock in the Dehui fault depression， Songliao Basin. The results show that：（1）The TOC of Cretaceous source rocks in Dehui fault Depression is generally greater than 1%，the organic matter types are mainly type Ⅲ，and type Ⅱ samples are mainly distributed in Non gannan Depression，which is generally in the mature to high mature stage of abundant gas；The source rocks of Huoshiling Formation and Yingcheng Formation were formed in the depositional environment of reduction-weak reduction and high-water salinity，and the lower biogenic sources such as plankton and algae contributed more in the source rocks of Huoshiling Formation in Nongannan Depression，and the oil generation capacity was stronger. （2）The composition of cretaceous natural gas varies greatly，with alkane gas ranging from 2.0% to 98.5% and CO2 content ranging from 0.1% to 96.5%；The main type of gas is coal-derived gas，and some gas samples show signatures of carbon isotope inversion because of secondary gas charging at different epochs. In the Guojia Depressions，Huajia Depressions and Nongannan Depressions，the hydrocarbon-bearing rocks are mainly the Huoshiling Formation. The gas in the Baojia Sink probably comes primarily from the source rock of the Zhuocheng For mation. The genetic type of CO2 gas is predominantly inorganic. As the burial depth increases，the carbon isotopic composition of the carbonate cement shows a positive shift，indicating the risk of drilling deep into the highly inorganic CO2 gas layer.（3）The source rocks in Nongannan Depression are in the stage of oil generation. From the south to the north，the thermal evolution degree of the source rocks increases gradually，which controls the phase distribution of“oil from the south to the north”and controls the hydrocarbon accumulation period. Industrial oil and gas wells are mainly located near the center of the high thick source rock，which controls the distribution of oil and gas reservoirs.
-
Characteristics and favorable zone distribution of tuff reservoirt of Cretaceous in A’nan sag，Erlian Basin
XIAO Boya
2024, Vol.36(6): 135–148
Abstract
(
79 )
PDF (11631 KB) (
116
)
doi: https://doi.org/10.12108/yxyqc.20240613
The tuff reservoir in the lower part of the first member of Cretaceous system in A’nan sag has become one of the key fields for tight oil exploration in Erlian Basin in recent years. Based on core observation，thin section authentication，reservoir physical property analysis and X-ray diffraction analysis，using the experimental methods such as high pressure mercury injection，nitrogen adsorption，field emission scanning electron micros copy and CT scanning，the characteristics of lithology，physical property，reservoir space type and pore struc ture of tuff reservoir of Cretaceous system in A’nan sag in Erlin basin were analyzed. Favorable tight tuff reservoir zones were predicted according to favorable reservoir formation mechanism. The results show that：（1）The tuff tight reservoirs in the lower part of the first member of Cretaceous Tenggeer Formation of A’nan sag of Erlian Basi，are mainly composed of tuff，tuffite，tuffaceous mud and tuffaceous sandstone.（2）The range of physical properties of tuff reser-voirs in the study area is largely，with average porosity is 4.88%. Among them，the num ber of samples with ultra-low porosity and extra-low porosity accounted for 83.6%，with the average permeability is 0.067 mD. It is an ultra-low porosity and ultra-low permeability reservoir. The tuff reservoir space include dis solved pores and devitrified pores，and have stereoscopic network pore structures，the tuff is mainly composed of mesopores and macropores，the physical properties are the best. The main reservoir spaces of tuffaceous sand stone include dissolution pore and intergranular pores，have micro-thin pore-micro throat pore structures，and mainly develop mesopores，with good physical characteristics. Tuffite and tuffaceous mud mainly develop dis solved pores，intercrystal pores and microcracks，have isolated pore structures，the pore types are mainly meso pores，with poor physical properties.（3）Sedimentation，diagenesis and tectonism jointly control the formation of high-quality tuff reservoir in the study area，sedimentation provide the material basis for the formation of highquality reservoirs，which control reservoir formation and distribution，compaction and cementation reduces reser voir physical properties，dolo-mitization and devitrification improves reservoir performance，the dissolution is the key factor of effective reservoir forming，which has positive impact on improving the physical properties of reservoir.（4）The tuff reservoir can be classified into three types，class Ⅰ，class Ⅱ and class Ⅲ. the reservoir in class Ⅰ is mainly concentrated around trough area，the reservoir in class Ⅱ is distributed in the form of stripes along the western gentle slope zone，the distribution range of reservoir in class Ⅲ is the widest，the areas where develop the reservoir in class Ⅰsuch as the east blocks of A43 well，the north blocks of A27 well，the west blocks of H16 well and south west blocks of A11well are the next favorable targets for tuff tight oil exploration.
-
Geochemical characteristics of Permian condensate oil and gas and phase types in southwest of Mahu Sag
WANG Yifeng, TIAN Jixian, LI Jian, QIAO Tong, LIU Chenglin, ZHANG Jingkun, SHA Wei, SHEN Xiaoshuang
2024, Vol.36(6): 149–159
Abstract
(
126 )
PDF (2098 KB) (
95
)
doi: https://doi.org/10.12108/yxyqc.20240614
The genetic types and its source of condensate oil and natural gas in Permian Formation，in southwest of Mahu Sag，is under controversy，the type of fluid phases is complex，which restricts the further expansion of deep oil and gas exploration in Mahu Sag. In this study，PVT phase simulation software was used to recover original reservoir fluid components oil and natural gas in Permian Formation，in southwest of Mahu Sag，com bined empirical statistical methods with P-T phase diagram to determine the phase types of discovered oil-gas reservoirs. The source and genetic types of different phase types of oil and gas is clarified by multiple means of geochemical analyses. The results show that：（1）The Permian oil and gas reservoirs in southwest of Mahu Sag are mainly distributed in Fengcheng and upper Urho Formation. The phase types of oil-gas reservoirs are multiple， black oil reservoir comes first，near critical high volatile reservoir and condensate gas reservoir（condensate gas reservoirs with oil rings and near-critical condensate gas reservoirs）comes second. Condensate gas reservoirs are mainly developed in Fengcheng Formation. The reservoir fluid components are mainly methane，and the content of C7+ hydrocarbons is relatively small.（2）The parent organic matter type of the different phases oil in the Permian are slightly sapropelic，all of which are the products of the mature stage source rocks in the Fengcheng Formation. The condensate oil maturity is slightly higher than the other phase oil，and its physical properties are better than others，with the characteristics of low viscosity，low freezing point and low wax content.（3）The natural gas components in the Permian are mainly hydrocarbon gas，of which the average methane mole fraction is 86.21%， the non-hydrocarbon gas content is low，the maturity varies greatly，the value of Ro is 0.52%-2.39%. It is mainly the product of sapropelic source rocks in the Fengcheng Formation. The maturity of natural gas of the upper Urho Formation is higher，with an average Ro value of 1.99%，while the natural gas maturity of Fengcheng Formation is lower，with an average Ro value of 0.71%. The natural gas average Ro of the condensate gas reservoirs of the Fengcheng Formation is 0.85%.（4）Due to the influence of the Fengcheng Formation source rocks thermal evo lution difference and the difference reservoir physical properties，The Permian developed two sets of oil and gas accumulation systems，the oil and gas reservoirs of Fengcheng Formation are self-generation and self-reservation within the source rock，and the upper Urho Formation is lower-generation and upper-reservation outside the source rock.
-
Heterogeneity of soluble organic matter in shale and occurrence state of shale oil under nanoconfinement
HONG Zhibin, WU Jia, FANG Peng, YU Jinyang, WU Zhengyu, YU Jiaqi
2024, Vol.36(6): 160–168
Abstract
(
86 )
PDF (18787 KB) (
141
)
doi: https://doi.org/10.12108/yxyqc.20240615
Taking the group components of medium-low maturity shale oil in the third member of Paleogene Shahejie Formation in the Bohai Bay Basin as an example，a nano-scale model of shale soluble organic matter system was constructed through molecular dynamic simulation. The molecular occurrence state of shale soluble organic matter system at the nanoscale under geological conditions was investigated. And the limiting factors of shale oil movability were analyzed. The results show that：（1）The shale soluble organic matter system model consists of four group components of saturated hydrocarbons，aromatic hydrocarbons，non-hydrocarbons，asphaltenes and water，with mass fractions of 18.6%，18.9%，19.7%，38.6%，and 4.2%，respectively. The representative mol ecules for each of the four group components are nC18，1-methylphenanthrene，the aromatic bicyclic structure with carboxylate-containing long-side-chain moieties，and C58H65NS，respectively.（2）In the initial state of simu lation，shale soluble organic matter system shows the uniform distribution of the various components with high energy. As the simulation progresses，the heterogeneity of the system increases and the energy decreases. The saturated and aromatic hydrocarbon molecules diffuse more easily，while the non-hydrocarbons and asphaltenes exhibit self-aggregation phenomena，resulting in the generation of a free subsystem dominated by dispersed small molecules（with a total mass fraction of saturated and aromatic hydrocarbons of 42.9%）and an aggregation subsystem dominated by macromolecular aggregates（with a total mass fraction of non-hydrocarbons and as phaltenes of 74.3%）. The free subsystem has a larger total molecular mass，66.7% of the total molecular mass of the original soluble organic matter simulation system，a faster diffusion rate，and a smaller density in the simu lated final state.（3）Molecular mass and polarity are essential factors affecting the mobility of shale oil in the nanoconfinement. Self-aggregation of polar molecules inevitably triggers heterogeneity in the soluble organic matter system，and the inhomogeneous distribution of polar molecular clusters，with adsorption in the nanopore throat space results in the blockage of shale oil transport channels，thus limiting the mobility of shale oil.
-
Characteristics and genetic mechanism of condensate oil and gas of the Jurassic Sangonghe Formation in western well Pen-1 sag，Junggar Basin
QIAO Tong, LIU Chenglin, YANG Haibo, WANG Yifeng, LI Jian, TIAN Jixian, HAN Yang, ZHANG Jingkun
2024, Vol.36(6): 169–180
Abstract
(
102 )
PDF (4820 KB) (
119
)
doi: https://doi.org/10.12108/yxyqc.20240616
Based on the analysis and test data of petroleum geochemistry，oil test and phase behavior analysis of condensate gas，basin modeling techniques were used to determine the characteristics，accumulation process and genetic mechanism of condensate gas reservoirs of Jurassic Sangonghe Formation in Qianshao well area of western well Pen-1 sag，Junggar Basin. The results show that：（1）The condensate reservoirs of Jurassic Sangonghe Formation are structural-lithologic reservoirs in western well Pen-1 sag. The high-quality reservoirs are mainly composed of gray fine-medium feldspathic detritus sandstone，with porosity ranging from 2.70% to 16.1%，an average value of 12.10%，permeability ranging from 0.016 mD to 109.000 mD，an average value of 14.17 mD. The reservoirs belong to middle porosity and low permeability reservoirs，and form reservoir-cap assemblage with two sets of source rocks from the underlying Permian Fengcheng Formation and lower Urho Formation.（2）The condensate oil in the study area is the product of the source rocks of lower Urho Formation within mature to high-mature stage，it has physical properties of low density，low viscosity，low freezing point and low wax content，and its n-alkanes are composed of low and medium carbon components.（3）The natural gas of condensate gas reservoirs in the study area is mainly composed of hydrocarbon gas，with concentrated distribution of methane and ethane carbon isotope values ranging from -37.40‰ to -36.84‰ and -27.55‰ to -26.54‰，respectively. It was derived from the cracking of humic-type source rocks of lower Urho Formation. （4）The condensate oil and gas generated by the source rocks of lower Urho Formation in the early Paleogene were continuously adjusted and finally charged in the early Neogene to form the present condensate gas reservoirs. The fluid composition has not changed since the reservoir formation，and the fluid phase type is also unchanged，so it is a primary condensate gas reservoir.
-
Simulation of microscopic seepage characteristics of CO2 immiscible flooding under the effect of diffusion and adsorption
CUI Chuanzhi, LI Jing, WU Zhongwei
2024, Vol.36(6): 181–188
Abstract
(
126 )
PDF (13966 KB) (
170
)
doi: https://doi.org/10.12108/yxyqc.20240617
Based on a two-dimensional model，a numerical simulation method was used to establish a numerical model of CO2 immiscible flooding，and the level set method is used to simulate the microscopic seepage laws of CO2 immiscible flooding and near miscible flooding under diffusion and adsorption. The microscopic seepage characteristics and diffusion adsorption characteristics of CO2 in pores were studied，and the influences of the injection velocity，diffusion coefficient，and adsorption reaction rate constant on the microscopic seepage charac teristics of near miscible flooding were analyzed. The results show that：（1）The degree of reserve recovery of the CO2 flooding numerical simulation using the phase field method is 51.29%，and the degree of reserve recov ery of theCO2 flooding numerical simulation using the level set method is 53.60%. The level set method is more suitable for simulating the seepage process of CO2 immiscible flooding.（2）Under immiscible flooding condi tions，CO2 preferentially diffuses into large pores，with a recovery efficiency of 87.7%，an outlet gas content rate of 71.60%，and a maximumCO2 surface adsorption concentration of 3.16×10-4 mol/m2. Under the conditions of near miscible flooding，CO2 is more likely to diffuse into small pores，with a recovery efficiency of 91.1%，an outlet gas content rate of 97.01%，and a maximum CO2 surface adsorption concentration of 5.81×10-4 mol/m2. （3）The microscopic seepage of miscible flooding is influenced by factors such as the injection velocity，diffu sion coefficient，and adsorption reaction rate constant. The injection rate increases，resulting in an increase in both the gas content and recovery rate at the outlet. An increase in diffusion coefficient and adsorption reaction rate constant will lead to an increase in recovery efficiency and a decrease in outlet gas content.