石油实验地质

2020, 42(6): .

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Abstract:

Spatial-temporal modelling of oil and gas accumulation in Changxing Formation in the Shunan area, Sichuan Basin

LI Yanjun, XIA Jiwen, LI Minglong, PU Hongguo, GENG Chao, WANG Hao

2020, 42(6): 877-885. doi: 10.11781/sysydz202006877

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There are three sets of source rocks below the Changxing Formation in the southern Sichuan Basin, including the mud shale in Lower Silurian Longmaxi Formation, the argillaceous rock in Middle Permian, and the coal series in Upper Permian Longtan Formation. Many large and medium-sized gas fields have been discovered in the Changxing Formation, but the understanding of the source of natural gas is still unclear. The natural gas composition and carbon isotope analyses show that the natural gas of Changxing Formation in this area is mainly secondary gas (from crude oil cracking) and is characterized by high methane content and high dryness coefficient, which belongs to typical dry gas. Combined with the reservoir microscopic characteristics and the inclusion homogenization temperatures, a spatial-temporal model of hydrocarbon accumulation was constructed. The natural gas of Changxing Formation in the southern Sichuan Basin is mainly from a deep Silurian hydrocarbon source mixed with a small amount of coal series gas in the Longtan Formation. The reservoir in Changxing Formation did not capture the liquid hydrocarbon generated by the source rock at the peak of oil generation stages, so it mainly accumulates gas. The early and middle period of Yanshan Movement is the main period of gas accumulation, with partial accumulation in the Yanshanian-early Himalayan. The natural gas of Changxing Formation in the southern Sichuan Basin is different from that in the eastern Sichuan which is mainly from the coal series. The spatial-temporal timing is the key to effectively capture oil and gas in traps and determines the source and accumulation enrichment of oil and gas. It is the core of modern petroleum accumulation research to reveal the migration and accumulation process of oil and gas through history.

Transpressional uplift of Wensu Uplift in northern Tarim Basin, NW China: evidence from seismic profiles

HE Guangyu, ZHAO Yongqiang, YAO Zewei, ZHENG Xiaoli, XIAO Sidong, HUANG Jiwen, JIA Cunshan, ZHOU Yushuang

2020, 42(6): 886-891. doi: 10.11781/sysydz202006886

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The Wensu Uplift is an important structural belt in the northern Tarim Basin, NW China, always regarded as a thrust belt. However, this recognition is not only incompatible with the facts that synthetic and antithetic faults are equally developed in thrusting systems on the seismic profiles, but also contradictory with the changeable thrust directions of the main faults. Based on the high-resolution seismic profiles, strike-slip deformation happened in the Wensu Uplift. It is because: (1) Two large flower structures are developed on seismic profiles; (2) The main strike-slip faults named as the Shajingzi and Gumubiezi faults, which are the main faults of two large flower structures mentioned above, thrust violently southward in the eastern section and northward in the western section, respectively; (3) The pre-Mesozoic units in the Wensu Uplift are ancient Sinian-Cambrian strata, which thrust southward and northward over the Mesozoic-Cenozoic strata in the Awati and Wushi sags, respectively. The strike-slip activities happened during the middle Caledonian (the latest Ordovician), the late Caledonian (the latest Silurian), the early Hercynian (the latest Early-Middle Devonian), the late Hercynian (Late Permian), Indosinian-Yanshan (the latest Triassic and Late Cretaceous) and Himalayan period (Paleogene, Neogene and Quaternary). These results indicate that the Paleozoic is not a uniform tectonic-sedimentary environment in the northern Tarim Basin because of the Wensu Uplift barrier.

Shale gas exploration potential and target of Permian Dalong Formation in northern Sichuan

WANG Wei, SHI Wenbin, FU Xiaoping, CHEN Chao

2020, 42(6): 892-899. doi: 10.11781/sysydz202006892

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The temporal and spatial distribution characteristics and basic geological conditions of organic rich shale in the Permian Dalong Formation in northern Sichuan Basin were studied based on the comprehensive analysis of geological and geophysical data. The Dalong Formation shale reservoir in the northern Sichuan region has favorable geological conditions of "high TOC content, high porosity, high brittle mineral content, and high gas content", showing a great exploration potential. The first significant property is the development of favorable facies belts in the deep-water shelf of the Dalong Formation in the northern Sichuan, with a thickness of 20-45 m and a wide areal distribution. Secondly, the average brittle mineral content of organic rich shale in the Dalong Formation is 82.3%, the organic matter type is humic-sapropel type, the average organic carbon content is 8.32%, the average thermal evolution degree(R_o) is 2.43%, the average porosity is 3.0%, and the average total gas content is 4.62 m³/t. The third positive factor is that the study area is separated from the basin-controlled Micangshan Fault by fault depressions, and the preservation conditions in the direction of the basin are good. It is proposed that the deep-water shelf facies of the organic-rich mud shale of the Dalong Formation in Nanjiang area is well-preserved, and the burial depth is moderate (2 000-5 000 m). It is a most favorable area for exploration in the near future.

Formation mechanisms and development models of dolomite reservoirs in Ordovician Yingshan Formation in Shunnan area, Tarim Basin

KANG Rendong, MENG Wanbin, XIAO Chunhui

2020, 42(6): 900-909. doi: 10.11781/sysydz202006900

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The dolomite reservoirs of the Ordovician Yingshan Formation in Shunnan area of the Tarim Basin have a great oil and gas potential. However, the genesis of different types of dolomite reservoirs is still subject to debate. In order to further deepen the understanding of the dolomite reservoirs in Shunnan area and clarify the genesis and development models of the dolomites in the Ordovician Yingshan Formation, the petrography and geochemistry of the dolomites were studied in detail, and some dolomitization models were established based on observation of core samples and thin section identification, using SEM, cathodoluminescence, carbon and oxygen isotope data and rare earth element pattern analysis. The petrographic analysis shows that the Yingshan Formation mainly develops three types of dolomite: powder-fine crystalline dolomite, fine-medium crystalline dolomite and fractured vug filling medium-coarse crystalline dolomite. Geochemical characteristics reveal that powder-fine crystalline dolomite is formed in water with higher salinity, which is the product of near-surface environment evaporation pump dolomitization. Fine-medium crystalline dolomite is formed in a buried environment. Medium-coarse crystalline dolomite is formed in relatively closed diagenetic environment, which is the product of tectonic-hydrothermal dolomitization.Medium-deep buried dolomitization can form large-scale fine-medium crystal dolomite with well-developed pores, which is the most favorable dolomitization for reservoir development.

Distribution characteristics and influencing factors of Middle-Lower Cambrian gypsum in southeastern Sichuan Basin

ZHU Yanxian, HE Sheng, HE Zhiliang, ZHANG Dianwei, ZHANG Shulin, SUN Ziming, TAO Ze

2020, 42(6): 910-919. doi: 10.11781/sysydz202006910

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The Middle-Lower Cambrian Longwangmiao Formation and Gaotai Formation in southeastern Sichuan Basin are gypsum rock layer systems, where gypsum rocks are widely developed and considered to be the Sinian to Middle-Lower Cambrian reservoir seals. Based on the drilling data and 2D seismic profile data, and combined with previous research results, this paper studies the lithologic features, vertical development and plane distribution characteristics of the gypsum rock layer system and analyzes the influence of tectonic compression on the flow deformation and plane distribution characteristics of gypsum rock. The gypsum salt and gypsum bearing lithologies in the Middle-Lower Cambrian gypsum rock layer system in the study area mainly include gypsum rock and dolomitic gypsum rock, as well as gypsiferous dolomite and dolomite with gypsum. The lithologic association and single layer thickness of the gypsum rock layer system vary greatly vertically. The gypsum rocks are widely distributed in the plane, but the accumulated thickness changes greatly. Under tectonic compression, the Middle-Lower Cambrian gypsum rocks in the low-steep folds in the southeastern Sichuan Basin usually flowed into the core of the anticline and obviously thickened. Crumpled, diapir and other associated structures developed. Due to the fluidity of gypsum rock, the plane variation of gypsum rock thickness is related to the structural deformation position of the low-folds, which is generally thickened in the anticline along the strike of the low-steep folds and obviously thinned in the syncline.

Characteristics and controlling factors of nano pores in shale reservoirs of Wufeng-Longmaxi formations in southern Sichuan Basin: insights from Shuanghe outcrop in Changning area

CAI Suyang, XIAO Qilin, ZHU Weiping, WANG Xiaolong, YUAN He, CHEN Ji, CHEN Shupeng

2020, 42(6): 920-927. doi: 10.11781/sysydz202006920

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Shale reservoirs within the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation(Wufeng-Longmaxi shales) have been one of the main targets for shale gas exploration and exploitation in the south of Sichuan Basin. This study focuses on the Wufeng-Longmaxi shales of the Shuanghe outcrop in Changning area, southern Sichuan Basin. Measurements including TOC, mineral composition, carbon dioxide and nitrogen adsorptions and FE-SEM were conducted on 41 samples to depict the nano porosity within the Ordovician Baota limestones and Wufeng-Longmaxi shale reservoirs and hence to clarify the regulating factors of the occurrence of nano pores. The Wufeng-Longmaxi shales are rich in organic matter. The mineral composition is dominated by biogenic quartz and carbonate minerals, followed by clay minerals and a small amount of feldspar. The nano pores in Wufeng-Longmaxi shales are dominated by silts, with pore diameters mainly distributed between 0.3-0.9, 40-50 and 100-200 nm, mainly organic pores, followed by mineral matrix pores. The occurrence of nano pores is controlled by the contents of organic matter, quartz and carbonates. Total pore volumes of selected samples are strongly correlated with TOC and quartz contents positively and carbonate contents negatively, and have no correlation with clays or feldspar. This indicates that nano pores within these samples are dominated by organic matter pores. The Ordovician Baota limestones are depleted in various nano pores, hence resulting in a good underlying sealing layer of Wufeng-Longmaxi shale reservoirs.

Deep thermal state and hydrocarbon accumulation potential of Cenozoic sedimentary basins in East China: a case study of Subei-South Yellow Sea basin

XU Xi, HU Hanwen, ZHANG Jiahong, XIAO Mengchu, GAO Shunli

2020, 42(6): 928-937. doi: 10.11781/sysydz202006928

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A remarkable phenomenon of the Cenozoic basins in East China is that there is a close correlation between the amount of post-rift thermal subsidence and the petroleum resources. In order to explore the underlying mechanism of this phenomenon and the correlation between deep thermal processes of sedimentary basins and the distribution of oil and gas resources, this paper takes the Curie interface depth estimated by the magnetic data as the first-order constraint for the deep thermal state to determine the quantitative relationship between it and the reaction rate of hydrocarbon generation from the cracking of kerogen. Moreover, the Subei-South Yellow Sea basin is an example of the outstanding positive correlation between hydrocarbon generation from source rocks and the deep thermal state, which could help to understand the tectonic-thermal system of sedimentary basin and hydrocarbon generation process, and offer a new research perspective for hydrocarbon accumulation and evaluation of petroleum potential.

Distribution and causes of present-day overpressure of Shahejie Formation in Linnan Subsag, Huimin Sag, Bohai Bay Basin

HUO Zhiying, HE Sheng, WANG Yongshi, GUO Xiaowen, ZHU Gangtian, ZHAO Wen

2020, 42(6): 938-945. doi: 10.11781/sysydz202006938

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The Linnan Subsag is a main hydrocarbon generating area in the Huimin Sag of the Jiyang Depression, Bohai Bay Basin. Oilfields mainly are in the subsag or on the southern and northern faults. Overpressure is found in the Shahejie Formation. Drilling, drill stem test (DST), logging and seismic data as well as the Eaton formula were applied to study the measured pressure characteristics in sandstones, the correspondence between logging and overpressure in both sandstones and shales, and the plane and profile distributions and causes of overpressure. The overpressure depth from DST ranges 3 005 to 4 355 m in sandstones of the Shahejie Formation, the residual pressure is 7.95 to 30.45 MPa, and the pressure coefficient is 1.21 to 1.78. Logged acoustic velocity of shale and sandstone in the overpressure zone is higher than that in the normal pressure zone, and the logged resistance of the overpressure zone is also higher than that of the normal pressure zone. The upper section of the fourth member and the middle and lower sections of the third member of Shahejie Formation mainly develop low overpressure, while medium and strong overpressure also exist regionally. Vertically, overpressure zones mainly occur from 3 000 to 4 500 m depth. There are several medium and strong overpressure zones, mainly in the deep sag and fault zone. The top depth of overpre-ssure zone is 2 500-3 700 m. The high percentage of sandstone leads to the limited distribution of overpressure in the Linnan Subsag. The overpressured sandstone reservoirs in this sag are mainly oil-bearing layers. Hydrocarbon-bearingfluid charging is the main reason for the overpressure of sandstones in the third and fourth members of Shahejie Formation in the Linnan Subsag. The high-quality source rocks are deeply buried. The vitrinite reflectance of the overpressured source rocks is about 0.5% to 1.5%. It is in the oil generation stage and does not have low density characteristics, indicating that oil generation is the main reason for the pressurization of source rocks.

Insoluble organic matter in source rocks: derived from organic macromolecules in the skeleton, cell wall and shell of organisms

QIN Jianzhong, PAN Anyang, SHEN Baojian

2020, 42(6): 946-956. doi: 10.11781/sysydz202006946

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Ultramicroscopic organic petrology analysis and other techniques were used to examine the relationships between organic detritus (from different types of biological skeleton, cell wall and shell) and insoluble organic matter in excellent source rocks from the point of view of molecular structure and stability of biological cells. Previous studies have shown that the organic skeleton, cell wall, shell and detritus in source rocks could be assigned to three main categories: (a) benthic algae, fungi, bacteria, pelagic algae and acritarchs; (b) shell, skin, hair and tendon as the connective tissue of zooplankton; (c) aquatic and vascular plants. The organic detritus playing the role of supporting or protecting the organisms were composed of inactive carbohydrate (e.g., cellulose, chitin, pectin, peptidoglycan) and inactive protein (e.g., scleroprotein). These biopolymers were chemically stable and insoluble in organic solvents and water. They were preserved in the form of insoluble organic matter (nonlipid) during the formation of excellent source rocks but without the ability to generate oil. They had hydrocarbon gas-generating capacity in the highly to early over-mature stage with a general conversion rate of hydrocarbon lower than 15%, which was equivalent to type Ⅲ kerogen or vitrinite.

Organic geochemistry and genesis of oil and gas seeps in the southern Junggar Basin

ZHOU Ni, LI Ji, LIU Cuimin, HE Dan, YANG Hongxia, WANG Haijing

2020, 42(6): 957-964. doi: 10.11781/sysydz202006957

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The geochemical characteristics of oil and gas seepages from southerm Junggar Basin were studied in order to determine the origin of complex seepages and their petroleum geology significance. The oil and gas seeps in the study area can be divided into 4 types. Type A is mainly distributed in the east section, mainly sourced from the Permian. Type B is mainly in the Qigu area, the first structural zone in the middle section and the Tuositai anticline in the west section, mainly sourced from the Jurassic. Type C is distributed in the second structural zone of the middle section, mainly from the Cretaceous. Type D is mainly distributed in Wusu-Dushanzi area of the west section, featured by mud volcanoes, with oil from the Paleogene and gas from the Jurassic. The distribution of oil and gas seeps shows a typical "source-fault" dual control mechanism, and has a good match with the main oil and gas systems, which is a direct indicator of underground oil and gas reservoirs on the surface. Further hydrocarbon exploration should be focused on gas in the upper segment in the west section, oil in the middle segment in the middle section, and favorable reservoirs in the lower segment of the east section.

Origin and significance of wellbore sediment in reservoir development: a case study of well Gaotan 1 in Junggar Basin

LI Erting, JIANG Yiqin, LIN Lili, DILIDAER Rouzi, XIE Like, ZHOU Ni, AN Ke

2020, 42(6): 965-971. doi: 10.11781/sysydz202006965

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During the development of oil and gas reservoirs, wellbore sediment will bring a series of problems, so it is important to identify the cause of wellbore sediment. The discovery in well Gaotan 1 is an important milestone in the history of oil and gas exploration in the Junggar Basin. However, with the exploitation of crude oil in this well, a large amount of black solid insoluble sediment blocked the wellbore. The composition of the sediment was clarified by various experimental analysis methods, such as group component analysis, gas chromatography, liquid chromatography, wax content analysis and pyrolysis experiments. The results allowed the study of the formation mechanism of the solid-phase sediment in well Gaotan 1 and the development of site control measures. The sediment in well Gaotan 1 is composed of soluble organic matter (mainly asphaltene) and silty sand (mainly fine silt). In the process of crude oil exploitation, the temperature and pressure of crude oil decrease from stratum to wellbore, and the light components in crude oil are preferentially separated and flow out, destroying the dynamic stability of the crude oil, and asphaltene dissolved in the crude oil to precipitate and flocculate, and finally to be adsorbed on the pipe wall. At the same time, silty sand at the bottom of the well is mixed with the asphalt precipitate with fluid flow, and grows with asphalt precipitate. This may be a common phenomenon in the oil and gas production process under high temperature and high pressure conditions. It is necessary to choose strong polar asphalt dispersants to increase the stability of the crude oil system, and use strong polar reagents for chemical cleaning of the scaled wellbore. More bottom hole filters are required to reduce sand and mud solid particles.

Chemical characteristics of formation water and the relationship with oil and gas preservation on northwestern margin of Junggar Basin

LI Tianyu, JIN Jun, TIAN Ying, ZHU Rong, LIU Yifeng

2020, 42(6): 972-980. doi: 10.11781/sysydz202006972

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The northwestern margin of the Junggar Basin is rich in oil and gas, and the relationship between oil and water is complicated. A large amount of formation water data was used to examine the vertical and lateral distribution of the water chemistry in oil-bearing strata from the Carboniferous to the Cretaceous. Combined with the geological background, the Hongshanzui Oilfield was dissected and the relationship between the chemical characteristics of formation water and the preservation of oil and gas is discussed. The results show that the formation water salinity decreases gradually when the burial depth varies from deep to shallow layers and the stratigraphic age varies from old to new. From the Carboniferous to the Cretaceous, the high salinity area of the formation water gradually migrates from the northwestern margin to the interior of the basin. The margin of the basin or the Ke-Wu fracture hanging wall is greatly affected by the infiltration and leaching of surface water or atmospheric water. The formation water is in a free alternating circulation zone, with low salinity, low chloride ion concentration Na₂SO₄ type or NaHCO₃ type water. The formation is poorly sealed, and heavy oil is usually formed. To the interior of the basin or the Ke-Wu fracture footwall, the formation water is in an alternating or stable stagnation zone, with a high degree of concentration. There mainly exists high salinity and high chloride ion concentration CaCl₂ type water. The formation has good sealing properties and forms well-preserved medium-light oil.

Geochemical characteristics and source analysis of crude oil from Archean buried hill JZ25-1S in Liaoxi Low Uplift

ZHAO Tingting, LUO Xiaoping, WU Piao, XU Yunlong, LUO Jian, SUN Yanxu

2020, 42(6): 981-990. doi: 10.11781/sysydz202006981

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The physical properties, group composition, stable carbon isotope, and biomarker compound distribution characteristics of crude oil in the Archean buried hill were studied and compared with the geochemical characteristics of Paleogene crude oil, in order to discuss the geochemical characteristics and sources of crude oil from the Archean buried hill JZ25-1S in the Liaoxi Low Uplift. The crude oil from the second member of the Paleogene Shahejie Formation and the Archean buried hill in this area are mainly light and medium crude oil. The oil has medium saturated hydrocarbon, high aromatic hydrocarbon, high non-hydrocarbon and asphaltene contents. The carbon isotopes of the crude oil are distributed between -26.2‰ and -24.4‰, and the isotopic fractionation among group components is small. The chromatographic curve clearly shows the "bulge" formed by biodegradation, the single peak and post-kurtosis state is dominant, the Pr/Ph value is generally around 1.3, and the Pr/nC₁₇, Ph/nC₁₈ values are both high. The sterane characteristics of crude oil show a high gammacerane abundance, the C₂₇ rearranged sterane and 4-methyl sterane contents are medium, the dinostane content is low, and the regular sterane C₂₇, C₂₈, C₂₉ fingerprints are partial"V" or "L" shaped. However, the characteristics of Archean crude oil from wells JZ25-1S-4D and JZ25-1-10D are quite different from the above-mentioned crude oil. Comprehensive analysis suggests that the main body of crude oil from the Paleogene and Archean buried hills in the JZ25-1S area is a mixture from the Es₃ member of the Liaoxi Sag and the Es₁ member of the Liaozhong Sag. Its parent material comes from a weakly reducing environment with moderate salinity and is mainly derived from algae and other phytoplankton. The crude oil has a high degree of maturity and is severely biodegraded. The Archean buried hill crude oil from wells JZ25-1S-4D and JZ25-1-10D is derived from the Es₃ member source rock in the Liaoxi Sag, which was deposited in a weakly reducing freshwater environment with high maturity and weak biodegradation.

Discovery and geochemical characteristics of Chang 7 source rocks from the eastern margin of a Triassic lacustrine basin in the Ordos Basin

HAN Zaihua, ZHAO Jingzhou, MENG Xuangang, SHEN Zhenzhen, YANG Rongguo, ZHANG Heng, GAO Feilong

2020, 42(6): 991-1000. doi: 10.11781/sysydz202006991

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Previous studies of source rocks in the Triassic Yanchang Formation in the Ordos Basin were mainly focused on the inner part of the basin, especially on the depocenter and its surrounding areas. Few investigations have been made with regard to source rocks on the "margin" of the lacustrine basin, particularly on the eastern margin. In order to make up for the limitations of previous work and determine whether effective source rocks are developed on the eastern margin of the Ordos Basin, we chose the Qilicun Oilfield in Yanchang County as our study area. The characteristics of the Chang 7 source rocks from the Qilicun Oilfield were studied through core observations, logging curve analyses and geochemical tests. The Chang 7 source rocks in the Qilicun Oilfield were widespread, with an area of over 2 500 km². They were subdivided into two types: black shale and dark mudstone, averaging 9.2 m and 28.9 m thick, respectively. The average TOC content of the black shale is 2.73%, which is in accordance with the "best" source rock standard. The average TOC content of the dark mudstone is 1.98%, which falls into the "good" source rock category. The organic matter is of types Ⅰ-Ⅱ₁, mainly generating oils. Maturity parameters show that there is no significant difference between the black shale and the dark mudstone, and both have entered the main oil generation stage. Biomarker analyses indicate that the Chang 7 source rocks were deposited in continental fresh water in a reducing environment. The black shale depositional environment was more reducing than that of the dark mudstone. The source organic matter is mainly derived from lower ranked aquatic organisms, with some higher land plants. Compared with the black shale, the dark mudstone has more contribution from terrestrial higher plants. The Chang 7 source rocks from the Qilicun Oilfield on the eastern margin of the Ordos Basin is the major source rock for hydrocarbon accumulation in this area. Moreover, the discovery of good quality source rocks suggests that the Chang 7 section on the eastern margin of the Ordos Basin such as the Qilicun field has significant potential for shale oil/tight oil exploration.

Microbial characteristics of low-amplitude structures and prediction of favorable target areas in Xinhe area, Tarim Basin

YAN Liang, JIA Baoqian, JI Miao, CHEN Xiaotong, GAO Ping

2020, 42(6): 1001-1008. doi: 10.11781/sysydz2020061001

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The Microbial Prospecting for Oil and Gas (MPOG) is an exploration method based on the seepage of light gaseous hydrocarbons from oil/gas reservoirs to the surface and their utilization by hydrocarbon oxidizing bacteria. By studying the abnormal characteristics of oil and gas microorganisms in Xinhe area of the Tarim Basin, this project provides a solid scientific basis for oil and gas prediction and the validation and application of oil and gas microbial exploration technology in this area. Soil samples were collected to investigate prospects for hydrocarbon exploration. The amount of cultivable soil microorganisms in different soil samples were analyzed using the agar plating method. High-throughput sequencing has been used directly to study the composition of microbial population in soil samples. Based on the data from Xinhe area, an abnormal pattern of oil and gas microorganisms has been established. By using this pattern, five abnormal microbial areas were identified in the Xinhe and Sandaoqiao area. Combined with the results of structural traps and the abnormal number of hydrocarbon microorganisms, five potential favorable exploration target areas were identified.

CO₂ EOR factors in heavy oil reservoirs

SUN Huanquan, WANG Haitao, WU Guanghuan, WANG Yiping

2020, 42(6): 1009-1013. doi: 10.11781/sysydz2020061009

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Different from the mechanism of improving light oil recovery by CO₂ injection, heavy oil does not mix with CO₂, so the main factors affecting its development are very different. Especially in the process of thermochemical composite oil recovery, the injected CO₂ mainly plays a role in insulating heat, reducing viscosity and increasing energy. The properties of heavy oil were determined in this study in order to systematically investigate the effects of different factors influencing CO₂ displacement. The effect of heavy oil viscosity, temperature, pressure and permeability on recovery were investigated using the orthogonal experimental method. Temperature was the most significant factor, followed by permeability, pressure and heavy oil viscosity. According to the experimental results and considering factors such as reservoir temperature and permeability, the field tests of CO₂ huff and puff in the Shengli Oilfield of SINOPEC were conducted. Production results show that increasing reservoir temperature and permeability is beneficial for CO₂ EOR and can improve oil production.

Optimization of target layer selection in shale gas horizontal wells

ZHAO Peirong

2020, 42(6): 1014-1023. doi: 10.11781/sysydz2020061014

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Through several years of exploration and development practices, China has realized the commercial development of shale gas from the Upper Ordovician Wufeng and Lower Silurian Longmaxi formations in the Sichuan Basin and its periphery. It has been recognized that shale gas reservoirs are self-generating and self-preserving with low porosity and permeability, which can be identified as the "artificial gas reservoir" and its production is mainly controlled by geological and engineering factors. Geological factors determine the shale gas enrichment, and engineering factors play a major role in shale gas yield. The accurate identification of "sweet spots" and the optimization of target layer selection in horizontal wells are so significant that they decide the final production of each shale gas well. A case study of target layer selection in the Jiaoshiba block of Fuling Gas Field shows that detailed research is the basis for identifying the target window, and the integration of geological and engineering technologies is the key to accurately identify the target layers. According to the specific geological conditions in different regions, applying both geological and engineering knowledge to pinpoint the target layer is an important factor for the ultimate success of shale gas exploration and development.

Analysis and identification of diamondoids by different mass spectrometry techniques

HUANG Ling, WENG Na, WEI Caiyun, SU Jin, ZHANG Bin, ZHANG Wenlong, HU Guoyi

2020, 42(6): 1024-1030. doi: 10.11781/sysydz2020061024

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Diamondoids have attracted extensive attention from researchers because of their important application value in oil and gas exploration. Since diamondoids have complex molecular structures and a large number of isomers, the identification of certain diamondoids is still controversial. In this paper, a qualitative study of adamantane derivatives, such as 1-ethyl-3-methyladamantane and 1-ethyl-3,5,7-trimethyladamantane, was carried out using gas chromatography-mass spectrometry, gas chromatography-triple quadrupole mass spectrometry and two dimensional gas chromatography-time-of-flight mass spectrometry. The chromatography peak position of these compounds in different mass spectrograms was confirmed. In addition, with the help of MASS FRONTIER software, the fragmentation mechanism and the characteristic ions formed during electron ionization was interpreted for 1-ethyl-3,5,7-trimethyladamantane in the ion source.

2020, 42(6): 1030-1030.

Abstract(339) PDF-CN(124)

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Analogue experiments on the piggyback propagation in northwestern Sichuan and latest propagation in its deeps

LUO Qiang, HE Yu, HUANG Jiaqiang, ZHANG Jing, LIANG Xiao, YU Hao, YANG Rongjun, DENG Bin

2020, 42(6): 1031-1040. doi: 10.11781/sysydz2020061031

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Recent explorations reveal a great potential for oil and gas resources in the northwestern Sichuan foreland basin. However, constrained by multi-phase tectonic activities of the Longmenshan-West Sichuan foreland system and the deep burial of the piedmont belt, there remain many uncertainties in the interpretation of petroleum structure models in the foreland concealed tectonic belt. Based on the geometry-kinematics-dynamic similarity theory between the foreland prototype of the northwestern Sichuan and the sandbox analogue model, two groups of controlled experiments were carried out (including standard scaled experiments and analogue experiments with a ramp-flat structure). The fold-thrust belt and foreland basin of the western Sichuan are controlled by two sets of main detachments of the Middle-Lower Triassic gypsum salt and the Lower Cambrian mudstone, leading the layered-style propagation to the foreland in the Late-Middle Cenozoic. The ramp-flat structure plays a profound influence on deep thrust and pop-up structures in the northwestern Sichuan foreland basin. Analogue results combined with seismic interpretation of the northwestern Sichuan illustrates that the main exploration potential may rely on the Paleozoic blind thrust and pop-up structures caused by the latest propagation to the northwestern Sichuan foreland basin.

The influence of water flooding multiples on reservoir micro pore structure

JING Hao, ZHANG Guangdong, SUN Dalong, LI Binhui, WANG Fenglan

2020, 42(6): 1041-1046. doi: 10.11781/sysydz2020061041

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Abstract:
Recent research on the micro-pore structure characteristics of reservoirs during long-term water flooding in a block of the Daqing Oilfield is non-systematic and falls short on the quantitative research on the micro-pore structure parameters at different water flooding multiples. This poses a challenge for revealing the mechanism of reservoir alteration. To resolve this problem, this paper develops and presents a method, combining nuclear magnetic resonance (NMR) with mercury intrusion, to determine the value of nuclear magnetic resonance conversion coefficient (C) with corresponding changes of rock physical properties. Utilizing high pressure mercury intrusion to calibrate the pore diameter by NMR overcomes the shortcomings that the samples in the same position are unable to be reused by mercury intrusion and the conversion coefficient, C value, of NMR can not be accurately determined. By the new method the core diameter and the change of core mineral composition under different water injection multiples, the porosity and permeability of all experimental cores increase to different degrees during long-term water flooding. Long term water flooding of the core increases the pore size and lowers the clay content. Furthermore, the experiments show that kaolinite is affected most. Clay mineral variation and particle migration are the main reasons for the change of rock physical properties and pore size.

2020, 42(6): 1047-1047.

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Abstract:

2020, 42(6): 1048-1057.

Abstract(316) PDF-CN(100)

Abstract:

2020 Vol. 42, No. 6

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