石油实验地质

2015, 37(2): .

Abstract(520) PDF-CN(859)

Abstract:

New insights into the physical percolation features of low-permeability reservoirs

Ji Bingyu, Zhao Yu, Song Kaoping, Xu Guanli

2015, 37(2): 129-133. doi: 10.11781/sysydz201502129

Abstract(1128) PDF-CN(1172)

Abstract:
For low-permeability reservoirs, interfacial tension, rock wettability and pore-throat ratio are important factors affecting production and recovery. Wettability index and wetting angle have a direct quantitative relationship with oil displacement efficiency. This paper presents a concept of modified capillary number associated with interfacial tension, rock wettability and pore-throat ratio, and establishes a wetting angle characterization method of low-permeability reservoir based on Amott wettability index and USBM index. We also derive a capillary number expression for low-permeability reservoirs and determine the relationship with residual oil saturation through core test. Based on this, the calculation formulas of a relative permeability curve, oil displacement efficiency and injection ability are given for different conditions of interfacial tension and wetting angle, which reveals the relationship between reservoir physical characteristics. The study provides a theoretical basis for optimizing chemical flooding, changing interfacial tension and wettability controlling parameters in low-permeability reservoir, and further improves oil displacement efficiency and recovery.

Current models and standardization of sequence stratigraphy

Li Baoqing

2015, 37(2): 134-140. doi: 10.11781/sysydz201502134

Abstract(997) PDF-CN(898)

Abstract:
Based on previous research, the paper summarized several sequence stratigraphic models (depositional sequence, genetic stratigraphic sequence and transgressive-regressive sequence) and standardized the workflow of sequence stratigraphy, and analyzed the merits and pitfalls of different sequence models. Sequence models representing stratigraphic records in different geological settings were applied to corresponding settings. The occurrence of system tracts was controlled by the interplay between accommodation and sediment supply, and was ascribed to changes such as tectonics, sea-level, sediment supply, climate and so on. The standardized workflow of sequence stratigraphy was based on the model-independent approach and model-dependent approach. Differentiating genetic types was essential for the standardization of sequence stratigraphy.

Characteristics and main controlling factors of shale gas reservoirs in transitional facies: A case study of Upper Paleozoic in Ordos Basin

Zhao Keying, Guo Shaobin

2015, 37(2): 141-149. doi: 10.11781/sysydz201502141

Abstract(1122) PDF-CN(1425)

Abstract:
Micro pores and micro fractures in shales are the main reservoir space and drainage channels for shale gas and the pore/fracture growth degree is related to gas content. To learn more about shale reservoirs of the Upper Paleozoic in the Ordos Basin, we classified the reservoir space into nanometer pores, micron pores and tiny cracks. Technologies such as scanning electron microscopy, argon ion polishing and nuclear magnetic resonance were applied to quantitatively characterize the development of different reservoir space. Combined with testing data such as TOC, organic composition and maturity, X-ray diffraction of whole rock and clay minerals, the controlling factors for different pore characteristics were analyzed. Two conclusions were made as follows. (1) The diameter of nanometer pores ranged from 17.13 nm to 67.65 nm on average, and the average plane porosity ranged from 5.75% to 9.37%. For micron pores, the average diameter was 3.17-5.61 μm, and the average plane porosity was 10.2%-19.32%. Tiny cracks accounted for 0.36%-0.72%. (2) TOC, organic maturity and I/S content promoted the generation of nanometer pores, while calcite content inhibited it. For micron pores, quartz and illite contents were positively correlated with their development, while carbonate content and burial depth were negatively correlated. Quartz content, organic maturity and TOC promoted the development of tiny cracks, while carbonate content inhibited it.

Characteristics and formation mechanisms of buried hill carbonate reservoirs in Bonan Low Uplift, Bohai Bay

Yu Haibo, Wang Deying, Niu Chengmin, Li Long

2015, 37(2): 150-156. doi: 10.11781/sysydz201502150

Abstract(1187) PDF-CN(1194)

Abstract:
The carbonate rock buried hills are important exploration and development targets in the Bonan Low Uplift of the Bohai Bay. Based on drilling, seismic, core, thin section and well logging data, the characteristics and formation mechanisms of the buried hill carbonate reservoirs were studied. They were divided into two reservoir systems, including the weathering crust karst reservoir and the inner dissolution reservoir. Dolomites were dominant, while limestones took second place. Reservoir space mainly included intercrystalline porosity, fractures and dissolved pores. The results of physical characteristic analysis showed that inequality grain dolomites, powder crystal-aplitic dolomites and silt crystal dolomites were better than limestones. Sedimentary facies, karstification and tectonic disruption were recognized as the main formation mechanisms of the buried hill carbonate reservoirs in the Bonan Low Uplift. (1) Sedimentary facies were the basis of reservoir formation. Favorable reservoirs mainly distributed in the dolomites and limestones of restricted sea, intertidal flat and tidal flat facies. (2) Karstification was the key to the formation of buried hill carbonate reservoirs. Weathering crust karst reservoirs and inner dissolution reservoirs developed within 0-250 and 0-150 meters under the top of the unconformity. Favorable karst reservoirs developed in the karst highland and karst slope of karst palaeogeomorphology. (3) Tectonic disruption was the connection of the formation of buried hill carbonate reservoir. Semi-filled or unfilled structural fractures and dissolution fractures provided important reservoir porosity and migration channels. When combined with dissolution pores, they formed fracture-pore and pore-fracture reservoirs, which improved reservoir performance.

Hydrocarbon accumulation conditions and patterns in the southwestern margin of Weixinan Sag, Beibuwan Basin

Zhang Ping, Zheng Jun, Xi Minhong, Wang Wenjun, Huang Jianjun, Wang Xiuping

2015, 37(2): 157-163. doi: 10.11781/sysydz201502157

Abstract(1073) PDF-CN(1110)

Abstract:
The hydrocarbon accumulation conditions and patterns in the southwestern margin of the Weixinan Sag of the Beibuwan Basin were studied based on modern reservoir theory, geophysics and geochemistry. Favorable hydrocarbon source rocks of semi-deep or deep facies developed in the Paleogene Liushagang Formation. Four sets of favorable reservoir and cap rock assemblages were deposited in the Paleogene. Faulted nose, faulted block and structure-formation complex traps formed. The good configuration of time and space was favorable for hydrocarbon accumulation. Two accumulation patterns, an upper one and a lower one, were determined, which were separated by an overpressure interface. For the lower system, hydrocarbon was self-generated, self-reservoir and migrated laterally, or upper-generated, lower-reservoir and migrated vertically. For the upper system, hydrocarbon was lower-generated, upper-reserved and migrated vertically. The steep and gentle slopes close to the deep depression were favorable exploration targets.

Petroleum accumulation diversity of Funing Formation in Weima area, northern slope belt of Gaoyou Sag

Xu Jian

2015, 37(2): 164-171. doi: 10.11781/sysydz201502164

Abstract(1651) PDF-CN(1002)

Abstract:
The Weima area is one of the richest oil fields in the northern slope of the Gaoyou Sag, and has a large amount of residual oil resources. Some problems, such as petroleum migration pathways and the factors controlling accumulation, are not solved yet. Based on the data of the oil shows in well logs, reservoir parameters and crude oil geochemical index, we analyzed the characteristics of source rocks, reservoirs, cap rocks, tectonics, carrier systems and oil and gas pools. Three types of crude oils (mature, low maturity and extra-low maturity) were found in the study area. According to the correlation of maturity between oil and source rock, it was pointed out that hydrocarbon in the study area was generated from the same source rock with different maturity levels in the north slope: mature oil source in the southeast of Majiazui area, mixed oil source with low maturity from the middle shallow sag and Cheluo saddle, and extra-low maturity oil source mixed with different maturity levels in the north. The geochemical parameters such as carbazole and thiophene, together with oil show features, were applied to study petroleum migration pathways, accumulation direction and hydrocarbon supply radius. The characteristics of hydrocarbon enrichment and fluid distribution were determined. The cause for a new reservoir type composed of both uniform and comb-like oil-water systems was described. The same source rock with different maturity levels was the material basis for the variation of oil enrichment in Weima area. Fault carrier systems were the main controlling factor for the direction and diversity of petroleum accumulation. In the end, two prospective areas were identified for potential petroleum resources.

Depositional features and forming mechanism of the limestone member of Funing Formation in Jinhu Sag

Su Juan, Liu Chensheng, Yu Wang

2015, 37(2): 172-178. doi: 10.11781/sysydz201502172

Abstract(1176) PDF-CN(1203)

Abstract:
The Paleogene limestone member in the Jinhu Sag is an important petroleum producing formation. However, the depositional features and forming mechanism of the limestone member are not clear, which brings difficulty for the forecast of reservoir. Different from peperites in other Paleogene basins in East China, the limestone member in the Jinhu Sag is the mixture of siliciclastic-carbonate sediments, based on the comprehensive analysis of core, seismic and logging data. The limestone member is mainly of lake, delta and lacustrine fan facies, among which the lake facies is dominant. The delta and lacustrine fan facies, controlled by faults and provenance, mainly distribute close to sediment sources. Clastic rock content decreases upwards in the limestone member, indicating the expansion of transgression, during which the limestone member was deposited. During the deposition of the limestone member, widespread syn-sedimentary faults served as the channels for sediment migration, and adjusted clastic rock distribution. Additionally, clastic rock deposition and provenance rechanneling made the terrain flat and water clear. As a result, biolithite limestones cover clastic rocks and there are no clastic rocks in the limestone. Provenance and faults are the main controlling factors for the limestone member in the study area.

Effective petroleum migration system in the Tertiary of Wen'an Slope, Jizhong Depression

Guo Kai, Zeng Jianhui, Jin Fengming, Xi Qiuling, Gong Xinghui

2015, 37(2): 179-186. doi: 10.11781/sysydz201502179

Abstract(949) PDF-CN(732)

Abstract:
Based on the analysis of the characteristics of faults and sand bodies, paleo-nose structures, fault activity and effective migration pathway index, the constitution and effectiveness of the migration system in the Tertiary of the Wen'an Slope of the Jizhong Depression and its effect on oil migration were studied. The migration system of the study area was mainly comprised of framework sandstones and many normal or reverse faults. Several paleo-nose structures towards oil sourcing sags located in the west of the Wen'an Slope and their match with the migration pathway system was favorable for oil convergence and migration towards the slope. Vertical migration was limited during large-scale oil migration, but lateral migration could occur through sand juxtaposition of different formations laterally adjusted by many NE faults. Ladder-like lateral migration over long distance from deep to shallow was the dominant migration pattern.

Genesis of large-amplitude tilting oil-water contact in Sarvak Formation in South Azadegan Oilfield, Iran

Du Yang, Yi Yingjie, Xin Jun, Chen Jie, Cui Yi, Tong Mingsheng, Ouyang Cheng, Wang Weibing

2015, 37(2): 187-193. doi: 10.11781/sysydz201502187

Abstract(1618) PDF-CN(1500)

Abstract:
The Sarvak reservoir of the South Azadegan Oilfield in Iran is a thick, block-like limestone reservoir of slack shelf sea deposition. The oil-water contact (OWC) of the reservoir is characterized as a large-amplitude one tilting from north to south. Hydrodynamic force and reservoir heterogeneity were studied, indicating that neither of which were the causes for the tilted OWC of the Sarvak reservoir. By investigating the evolution of areal tectonic setting, utilizing a formation flattening technique to recover the paleo-structure of different geologic stages, and combining with accumulation factor analysis, it was determined that the adjustment of traps after the Zagros orogeny led to the tilted oil-water contact. A paleo-trap which decreased from north to south (reversed from the present situations) formed in the Sarvak Formation in the SA Oilfield after the late Paleocene. The Zagros orogeny during the Neogene caused the adjustment of the trap, and the former low point in the south uplifted significantly and gave birth to a new secondary trap. As a result, the present tectonic setting with two high points (higher in the north and lower in the south) was formed. The balance in the paleo-trap was broken, and hydrocarbon migrated to the secondary trap in the south and was still adjusting now. The large-amplitude tilting oil-water contact showed that the paleo-reservoir was still adjusting and unstable.

Main controlling factors and exploration potential of hydrocarbon reservoirs in North Gabon sub-Basin

Guo Nianfa

2015, 37(2): 194-197. doi: 10.11781/sysydz201502194

Abstract(962) PDF-CN(1251)

Abstract:
The North Gabon sub-Basin is a Mesozoic-Cenozoic rift and divergent margin basin. The oil and gas reservoirs in the basin were controlled by tectonic movements, sedimentary environments and salt structures. The east of the basin was eroded due to regional uplift, and source rocks and hydrocarbon reservoirs were destroyed, leading to a significant difference of hydrocarbon potential between the east and the west tectonic belts. Sedimentary environments impacted reservoirs. The Upper Cretaceous turbidity sandstones and offshore sandstones were important reservoirs for the post salt layers. Various traps developed, which were related to salt structure activities. Based on research of the turbidity sandstones and offshore sandstones of the post-salt layers, the main hydrocarbon reservoirs of the North Gabon sub-Basin mainly lie on the middle-south, deep ocean slope belt, which is the center of the major source rocks of the Azile Formation. Thanks to favorable sourcing and reserving conditions, the middle-south, deep ocean slope belthas considerable hydrocarbon prospects.

Control of compression-shearing and strike-slipping on deep-water carbonate reservoir reconstruction: A case study of the west tip of Sinjar Uplift

Zhao Zhongping

2015, 37(2): 198-204. doi: 10.11781/sysydz201502198

Abstract(980) PDF-CN(843)

Abstract:
Through analyzing the relationship between the structural characteristics and oil reservoir distribution of Eocene Jaddala and Oligocene Chilou formations in the western tip of the Sinjar uplift, this paper documents that compression-shearing and strike-slipping transformed the deep-water tight carbonate rocks into favorable reservoirs. The reconstruction was in two aspects: (1) Strike-slip shearing made the tight carbonate rocks into fractured reservoirs; and (2) local uplifts and folds generated by the compression components of a twisting couple during early tectonic inversion stages were elevated near or above the sea level, so that the tight carbonate rocks were leached by a mix of sea water and rain, which generated porous reservoirs. This case showed that the deep-water tight carbonate rocks altered by tectonic activity had exploration potential, and similar local structures provide potential prospects during the exploration and exploitation of oil and gas.

Petroleum accumulation characteristics and favorable exploration area prediction in San Jorge Basin, Argentina

Tian Naxin, Jiang Xiangqiang, Hui Guanzhou

2015, 37(2): 205-210. doi: 10.11781/sysydz201502205

Abstract(1098) PDF-CN(1082)

Abstract:
The San Jorge Basin is one of the most important prolific petroliferous basins in Argentina. It experienced four tectonic evolution stages and a double-layer structure was formed, which is composed of a rift system formed in the Triassic-Early Cretaceous and a depression system formed in the Early Cretaceous-Cenozoic. Based on the study of regional tectonic and depositional evolution, integrated with the latest drilling data, hydrocarbon accumulation characteristics and controlling factors were studied. The Upper Jurassic-Neocomian Group of the Lower Cretaceous and lacustrine shale in the D-129 Formation of the Lower Cretaceous are the main source rocks. The Cretaceous Chubut Group sandstone is the main reservoir. The Chubut Group lacustrine mud shale is the most important cap. Various trap types were formed due to rifting, depression and the Andean orogeny. Hydrocarbon accumulations were controlled by the distribution of mature source rocks and fault systems. The size of oil and gas pools was controlled by fluvial facies sandstones. Oil and gas distribute circularly around the basin center. The favourable exploration areas for the upper part of the Cretaceous Chubut Group sandstone, the Cretaceous D-129 Formation and the Upper Jurassic-Lower Cretaceous Neocomian Group were predicted.

Causes of natural gas geochemical differences in the high-temperature and overpressure zone of DF1-1 diapir belt, Yinggehai Basin

Wu Hongzhu, Huang Zhilong, Pei Jianxiang, Tong Chuanxin, Zhu Jiancheng, Liu Ping, Zhu Shanshan

2015, 37(2): 211-219. doi: 10.11781/sysydz201502211

Abstract(864) PDF-CN(413)

Abstract:
Natural gas geochemistry, fluid inclusion analysis and gas reservoir accumulation tracers, have been used to study natural gas geochemical characteristics, genetic types, filling period, cause of carbon-isotope partial inverse sequence and the causes of gas variability both vertically and horizontally in the high-temperature and high-pressure belt in the central diapiric zone of the Yinggehai Basin. In the high-temperature and overpressure area, natural gas is thermogenic coal-type gas, and the partial inversion of carbon isotopes of alkane gas is caused by the mixture of multi-period gases that are of different maturities. There are four periods of fluid filling in the high-temperature and overpressure area. The first two periods are mature or high-maturity alkane gas, while the second two periods are high-maturity or over-mature alkane gas and inorganic CO₂.The filling period of the high-maturity and over-mature alkane gas is earlier than that of the inorganic CO₂. The influence of different diapiric activity, together with different gas migration channel types and development is the main reason for gas differences in different high-temperature and high-pressure zones. Multi-periodic diapir activity and periodic occurrence of overpressure caused the gas chemistry differences inside and outside of the high-temperature and high-pressure zone in the diapir core of D1-1 and nearby D13-1.

Application of headspace single-drop microextraction (HS-SDME) technique in geochemical exploration for petroleum

Zhao Jing, Liang Qianyong, Xiong Yongqiang, Li Yun, Fang Chenchen

2015, 37(2): 220-225. doi: 10.11781/sysydz201502220

Abstract(1115) PDF-CN(462)

Abstract:
All surface geochemical exploration methods for oil and gas are based on the theory that hydrocarbons generated and trapped at depth seep in varying but detectable quantities to the surface, and the main components detected are usually C₁-C₅ hydrocarbons. The C₁-C₄ hydrocarbons could come from degradation of organic matter by microbial organisms, while the gasoline range hydrocarbons are totally sourced from thermogenic processes. Therefore, the detection of gasoline range hydrocarbons in soils or sediments could be the most direct evidence for hydrocarbon seepage and the method used to detect the C₆-C₁₂ range hydrocarbons could be a useful technique for surface geochemical exploration method for petroleum. However, because the concentration of gasoline range hydrocarbons in the soils or sediments are usually very low, and the present techniques for detecting those hydrocarbons are not adequate, the gasoline range hydrocarbons have seldom been used in surface geochemical exploration for oil and gas. In this study, the headspace single-drop microextraction (HS-SDME) technique coupled with gas chromatography-flame ionization detection (GC-FID) was employed to determine C₆-C₁₂ gasoline range hydrocarbons in well drilling mud sample. The results show that the C₆-C₁₂ hydrocarbons in the samples could be detected by HS-SDME, and the reservoir depth determined by the concentration of C₆-C₁₂ hydrocarbons was the same with the actual petroleum reservoir depth, which indicated further that the HS-SDME method could be used in geochemical exploration for petroleum.

Research progress on composition of individual oil inclusion

Wang Aiguo, Yi Liping, Shi Lei, Wang Yisong

2015, 37(2): 226-230. doi: 10.11781/sysydz201502226

Abstract(1228) PDF-CN(462)

Abstract:
The composition of individual oil inclusion is significant to the studies of hydrocarbon migration and accumulation; however, how to obtain it accurately is a global problem. Research methods and technologies of individual oil inclusion are reviewed and analyzed through literature research. On the whole, these methods can be summarized as a crushing test, composition estimation and in situ nondestructive analysis. Each method has its advantages and limitations, thus the problem of the composition of an individual oil inclusion has not been resolved completely. Further research is demanded in developing new analytical methods and upgrading research equipment.

Pore characteristics of a shale gas reservoir and its effect on gas content

Wu Yanyan, Cao Haihong, Ding Anxu, Wang Liang, Cheng Yunyan

2015, 37(2): 231-236. doi: 10.11781/sysydz201502231

Abstract(1315) PDF-CN(995)

Abstract:
The porosity tests of 24 Longmaxi Formation shale samples fromthe southeastern Chongqing area and 10 Xujiahe Formation shale samples fromthe southeastern Sichuan area were carried out with argon ion milling+ scanning electron microscopy (SEM) and nitrogen adsorption methods. The effect of porosity difference on gas content was discussed. Shale pores are usually organic pores, mineral inter-particle pores,dissolution pores, inter-granular pores and inter-laminar cleavage cracks, and most of the pore shape was irregular and open.The pore structure of the samples was complex. Nano-scale organic pores were common in the Longmaxi Formation shale samples, and the pore diameter was 2-10 nm. Inorganic middle-large pores and micro-cracks were dominant in the Xujiahe Formation shale samples. The pore characteristics might result from different chemical mole-cular properties of organic matter in the shale, or a catalytic relationship between inorganic mineral or element and organic matter. Statistical results showed that the pore types were not the main controlling factors of gas content: TOC was the most essential factor for shale gas reservoir.The pore structure of the Xujiahe Formation shale samples was mainly affected by inorganic minerals.TOC was the dominant factor of specific surface area and 2-10 nm pores in the Longmaxi Formation shale samples, and provided the main storage space for shale gas.Illite was an important factor for 2-10 nm pores, which provided the main storage space for the Xujiahe shale gas.

Mechanism and quantitative evaluation method of the petroleum migrationn system

Lin Yuxiang, Sun Ningfu, Guo Fengxia, Yan Xiaoxia, Meng Cai, Li Xiaofeng, Liu Hu, Li Xiuqin

2015, 37(2): 237-245. doi: 10.11781/sysydz201502237

Abstract(1191) PDF-CN(431)

Abstract:
A classification scheme for the petroleum migration system was proposed through the analysis and summary of the migration systems of the main petroliferous basins in China in order to reduce the multiple solutions and make more objective and accurate evaluation possible. The migration elements were classified into three types. The first type was the necessary elements, which included transportation space, power and fluid. The second type was a variety of elements that described the significant features of the migration system, including direction and capability. The third type was the elements that complemented the migration system, such as the scale and hierarchy as well as the formation and function period of the migration system. Based on the migration mechanism, a new nomenclature of the system was proposed: the scale and hierarchy of the migration system + the period of formation and function + fluid transport direction + the capability of transporting fluid+ migration power + migration space. Moreover, according to the contribution of elements on oil and gas migration and accumulation, this article systematically summarized the quantitative evaluation criterion and the assignment principle of the merits of each migration element. The restoration methods and steps of ancient migration system were determined. The recovery of paleo-pores and paleo-structure was the key to migration system recovery during the accumulation period. The method paved the way for the quantitative evaluation of migration, and made it possible to predict potential oil and gas reservoirs better and to improve the exploration success ratio.

Characteristics of reservoirs related to salt structure and its experimental simulation in the southern margin of Precaspian Basin

Yang Tai, Tang Liangjie, Yu Yixin, Zheng Junzhang, Wang Zhen, Kong Linghong, Wang Yankun

2015, 37(2): 246-251. doi: 10.11781/sysydz201502246

Abstract(987) PDF-CN(513)

Abstract:
Based on the interpretation of seismic profiles and hydrocarbon accumulation simulation, the characteristics of salt-related structures and reservoirs in the southern margin of Precaspian Basin are analyzed. Salt diapirs and salt walls are the main structure types in the study area, with welds, rolls or bedded layers of salt playing a connecting role between them. There are two hydrocarbon accumulation mode types, one associated with salt welds in the postsalt formations and the one with heterogeneous reservoirs in the presalt formations, divided by the salt layer. The 2D experimental modeling of oil migration and accumulation indicates that salt welding is the key of oil accumulation in the postsalt formations, while faults and interlayer heterogeneity control the distribution of oil in the presalt formations. The result is significant for understanding the oil migration and accumulation in salt-related structures and guiding oil exploration and development of salt-bearing basins.

Slice experiment of oil-bearing core rock and its implications

Luo Qingyong, Zhong Ningning, Li Kewen

2015, 37(2): 252-258. doi: 10.11781/sysydz201502252

Abstract(873) PDF-CN(478)

Abstract:
The contamination of rocks during drilling, sampling, storage or handling processes will affect the organic geochemical information of biomarkers, and will even lead to the wrong interpretations of the origin and evolution of early life on the earth especially for preCambrian sediments. A slice experiment was employed on the oil-bearing argillaceous dolomite from the Hongshuizhuang Formation in order to discuss the influence of contamination on biomarkers. The aliphatic biomarkers showed a big difference between outside oil show (OOS) and inside oil show (IOS), whereas the difference for the aromatic biomarkers was small. Most of the biomarker ratios showed a considerable discrepancy between OOS and IOS except a few parameters. Steranes were not detected in the IOS, indicating that the existence of steranes remained for further validation. It was recommended that cutting the surface of core samples before organic geochemical experiments could avoid contamination.

Numerical simulations of tectonic stress fields for Late Mesozoic-Paleogene extensional tectonics in western Shandong

Hu Qiuyuan, Li Li

2015, 37(2): 259-266. doi: 10.11781/sysydz201502259

Abstract(835) PDF-CN(677)

Abstract:
Extensional tectonics in the West Shandong Uplift were examined and geological models were established using field geological survey data of the western Shandong and the geophysical data of the Jiyang Depression. Based on a finite element method, we adopted the Ansys12.0 software to carry out a 3D tectonic stress field numerical simulation of the extensional tectonic evolution of the study area from the Late Mesozoic to Paleogene, which fit well with the actual geological conditions. The results indicated that the tectonic stress field evolved from strong to weak from the Late Mesozoic to Paleogene, and the maximum principal stress axis transferred from NW-SE to NWW-SEE, and then to NE-SW, which was a major shift. Paleocene-Early Eocene was a transitional period with its stretching orientation transformed from NE-SW to NS, and Eocene-Oligocene was a significant phase for uplift-depression differentiation when the West Shandong Uplift and the Jiyang Depression became separated and evolved separately. This evolution regularity had an important control on the migration and accumulation of oil and gas in the Jiyang Depression and the enrichment of metallic minerals in the West Shandong Uplift. The essential factors leading to the tectonic evolution were the changes of the Pacific Plate subduction, the strike slipping motion along the major boundary fractures, and the magma under plating.

Jiang Qigui

2015, 37(2): 267-267.

Abstract(563) PDF-CN(369)

Abstract:

2015 Vol. 37, No. 2

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