石油实验地质

2022, 44(4)

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Abstract:

Main controlling factors and exploration direction of Permian to Triassic reservior in the central sag of Junggar Basin

ZHANG Zhongpei, ZHANG Yu, ZHANG Mingli, LU Hongmei, ZHANG Rongqiang, CHEN Yuanzhuang, WANG Hanzhou, LI Pengwei

2022, 44(4): 559-568. doi: 10.11781/sysydz202204559

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Abstract:
In recent years, significant oil and gas discoveries have been achieved in the Permian Upper Wuerhe Formation and the Triassic Baikouquan Formation on the marginal slope of oil generation sag, Junggar Basin. However, in the central sag of the basin, no oil or gas show has been discovered in target formations, and low production has been made only by two wells. As a result, it is necessary to deepen the understanding of the mechanisms of oil and gas accumulation and clarify the main controlling factors. The analyses of the accumulation conditions in the central sag and some wells show that the direct reason for the failure to find oil and gas in the sag is the lack of local source-connecting faults and poor reservoir properties. An accumulation model with source in the lower section and reservoir in the upper section controlled by both source-connecting faults and favorable sand bodies was established for the Permian and Triassic strata in the sag. The sandbody lithologic reservoirs of fan-delta front subfacies in the Upper Wuerhe and Baikouquan formations under the background of stratigraphic overlap are the primary direction of exploration, covering an area about 3 600 km². The comprehensive exploration of unconventional oil and gas in the Middle-Lower Permian source rocks and conventional oil and gas in multiple layers outside the source area should be targeted.

Lithological influences to rock mechanical properties of Permian Fengcheng Formation in Mahu Sag, Junggar Basin

LI Peng, XIONG Jian, YAN Qi, ZHU Zhengwen, LIU Xiangjun, WU Jun, WANG Zhenlin, ZHANG Lei

2022, 44(4): 569-578. doi: 10.11781/sysydz202204569

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To reveal the mechanical properties of the rocks of the Fengcheng Formation, the rocks of the Lower Permian Fengcheng Formation in the Mahu Sag of Junggar Basin were taken for the laboratory mechanical tests to obtain mechanical behaviors of the rocks, the influence of mineral compositions on strength parameters of the rocks of the Fengcheng Formation was then discussed. The rocks of the Fengcheng Formation in the Mahu Sag have strong heterogeneity, which results in obvious differences of mechanical properties of rocks with different lithologies. The mechanical strength and elastic modulus of dolomitic rocks are higher, but the Poisson's ratio is lower. The form of rock fracturing is relatively simple. Under uniaxial conditions, rock samples have strong brittleness, which is characterized by tensile fracturing, while under high confining pressure, rock samples have weaker brittleness and enhanced ductility, which is mainly characterized by single shear fracturing. The compressive strength, tensile strength and fracture toughness of rocks decrease with the increase of siliceous mineral content, while increase with the increase of calcium mineral content.

Reservoir characteristics and controlling factors of physical properties of Jurassic Toutunhe Formation in the eastern segment of the southern margin of Junggar Basin

LIU Ke, GAO Chonglong, WANG Jian, LIU Ming, LUO Zhengjiang, WANG Ke, DENG Yi, REN Ying

2022, 44(4): 579-592. doi: 10.11781/sysydz202204579

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The lower assemblage (from Jurassic to Cretaceous) on the southern margin of Junggar Basin is rich in oil and gas resources, and the Jurassic Toutunhe Formation in the eastern segment is an important horizon for reservoir development. However, no systematic study has been accomplished for its reservoir characteristics and controlling factors of physical properties. Based on the drilling and logging, microscopic observation of thin section, scanning electron microscopic observation, physical property and mercury injection test, vitrinite reflectance (R_o%) and other data including coring wells, combined with regional geological background and stratigraphic conditions, it was analyzed in this paper for the basic characteristics, diagenetic evolution and controlling factors of physical properties of Toutunhe Formation. The sedimentary hydrodynamic conditions of the Toutunhe Formation in the eastern segment of the southern Junggar Basin are relatively stronger, which makes the content of matrix inside the reservoirs relatively lower. It has the petrologic characteristics of low compositional maturity, high plastic debris content and medium structural maturity. The reservoir space is dominated by inter-granular pores, with an average porosity of 11.6% and an average permeability of 5.7×10^-3 μm². The whole reservoir belongs to low-porosity and low-permeability or medium-porosity and medium-permeability reservoir. Medium and large pores and coarse throats are dominant, relatively well sorted. Reservoir diagenesis is dominated by compaction, cementation and dissolution, but the content of cement is low. The dissolution effect is mainly acidic dissolution. The overall diagenesis degree of the reservoir is low, mainly in the early diagenetic stage A-B with some in the middle diagenetic stage A. Compaction effect, including both structural and burial ones, lead to the decrease of porosity in the Toutunhe Formation. In addition, the cementation of carbonate and clay minerals further reduces the physical properties of the reservoir. Although the effect of dissolution for porosity enhancement is relatively limited, the reservoir has begun to enter the middle diagenetic stage, the effect of formation acid fluid will strengthen in the deep layer, which will increase dissolution porosity. Due to the slow burial in the early stage, rapid deep burial and rapid uplift in the later stage, combined with the occurrence of formation overpressure and the continuous reduction of geothermal gradient, the physical properties of the Toutunhe Formation have been effectively preserved.

Geochemical characteristics and fluid origins of fracture- and cave-filling calcites of Ordovician in Yubei area, Tarim Basin

LI Miao, ZHOU Yushuang, ZHAO Yongqiang, GENG Feng, QIAO Guilin, HAO Jianlong

2022, 44(4): 593-602. doi: 10.11781/sysydz202204593

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The genesis of carbonate reservoirs of the Lower-Middle Ordovician strata has been an important topic for petroleum exploration in the Yubei area, Tarim Basin. To investigate the stages and properties of paleo-fluid and discuss the reservoir origin, the geochemical and cathodoluminescence features of the Ordovician fracture- and cave-filling calcites from wells in the Yubei area were analyzed combining with the regional tectonic background. Results show that the REE distribution patterns and occurrences of samples from different wells have the characteristics of seawater and fresh water, respectively. The average values of Sr isotopes gradually decrease from east to west. Moreover, the average value of ⁸⁷Sr/⁸⁶Sr in high-angle fracture calcites is higher than those of cave-filling and horizontal-fracture calcites, suggesting obvious variations of fluid properties in different regions and sample occurrences. Therefore, the diagenetic environment of the Lower-Middle Ordovician carbonates in the Yubei area may be open. The decreases of meteoric alteration from east to west can be attributed to the Middle Caledonian and Early Hercynian tectonic setting. Moreover, the progress of reservoir modification by fluids is mainly affected by fault activity intensity.

Types and features of diagenetic fluids in Shunbei No. 4 strike-slip fault zone in Shuntuoguole Low Uplift, Tarim Basin

SONG Gang, LI Haiying, YE Ning, HAN Jun, XIAO Chongyang, LU Ziye, LI Yingtao

2022, 44(4): 603-612. doi: 10.11781/sysydz202204603

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The Shunbei No. 4 strike-slip fault zone is an important exploration target in the Shuntuoguole Low Uplift of Tarim Basin, and the Middle Ordovician carbonate is a major hydrocarbon-bearing stratum. Fault structures and accompanied fluids play a key role for the distribution of carbonate reservoirs, and it is therefore important to study the fluids accompanied with fault evolution. Petrography, in situ Sr isotopic compositions, in situ rare earth elements (REE) and U-Pb dating were carried out to reveal the fluids from which the calcites in fractures precipitated. The calcites in fractures show ⁸⁷Sr/⁸⁶Sr ratios of 0.708 498-0.709 177, and the REE patterns of the calcites are characterized by negative Ce anomaly, positive Eu anomaly and high Y/Ho ratios. The calcite samples show U-Pb isochron age of (433±17) Ma and (449±15) Ma, respectively. The ⁸⁷Sr/⁸⁶Sr ratios and REE patterns of the calcites suggest that parent fluids experienced elevated temperature environment and buffered by carbonate host rocks. The U-Pb isochron age implies that the calcites may record the fault-related fluids during the Ⅲ stage of the Middle Caledonian Movement, which might be associated with the Altyn orogeny.

Microbial characteristics of soil in low-amplitude structures in Yuqi area, Tarim Basin

LI Wu, WANG Guojian, YAN Huan, JIA Baoqian

2022, 44(4): 613-619. doi: 10.11781/sysydz202204613

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High-throughput sequencing of microbial 16S rRNA gene has been conducted to explore microbial diversity and community structure in the Yuqi oil and gas reservoir sites of Tarim Basin. Soil samples were collected from Yuqi oil and gas reservoir sites (YQ-y) to the east of well YQ 5 and prospecting areas (YQ-wz) to the west of well YQ 12. Most of the two groups of sample have similar microbial community. Both α- and β-diversity analyses show that YQ-y and YQ-wz samples have great similarity in species abundance, diversity and community structure. Ten major hydrocarbon-oxidizing bacteria were identified in the YQ-y and YQ-wz samples, including Methylophaga, Bacteroides, Nocardioides, and Bacillus. Moreover, a large number of unknown bacteria were noticed, indicating that both of the samples contain abundant unknown microbial resources. Oil and gas microbial diversity in the Yuqi area was obtained through high-throughput sequencing. The two groups of samples from YQ-y and YQ-wz areas have similar microbial community. Preliminary discussion on microbial anomaly in the eastern part of Yuqi was also carried out.

Geochemical characteristics of paleo-fluids in thrust belt in the northern Middle Yangtze and its significance for shale gas preservation: a case study of well Baodi 1

LIU An, WANG Qiang, CHEN Xiaohong, LI Xubing, Zhang Baomin, LI Hai, Li Jitao

2022, 44(4): 620-628. doi: 10.11781/sysydz202204620

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To study the geochemical characteristics of paleo-fluids in the Dahongshan thrust belt of Middle Yangtze and its significance for shale gas preservation, in this study, Silurian vein samples were collected from well Baodi 1 and fluid geochemistry and inclusions were systematically analyzed. Results show that the variation range of δ¹³C of calcite veins is -8.19‰ to 0.16‰, with the minimum value much lower than that of Silurian limestone interlayer and marine carbonate. The desulfurization coefficient of vein inclusion group is 23.53 to 87.90, with downward trend from bottom to top. It is indicated that the SO₄^2- in paleo-fluid of Silurian increases because of the mixing of underlying Cambrian gypsum brine, as well as CO₂ and H₂S entering into Silurian along fracture system from Cambrian TSR productions, resulting in negative δ¹³C of calcite veins and H₂S show in drilled formations. The inclusions at the bottom of Silurian Longmaxi Formation are mainly pure aqueous solution inclusions. The maximum homogenization temperature peak is about 110 to 120℃, and the minimum homogenization temperature distribute from 60 to 80℃. Compared with those in the eastern Sichuan Basin, the shale in Dahongshan thrust belt entered uplifting and denudation stage earlier, and the paleo-fluid formation stage had shallower burial depth, low temperature and low gas saturation. The range of homogenization temperature of inclusions near the detachment zone is wider, and the lowest homogenization temperature is developed in this section, indicating the detachment zone has more periods of tectonic activity and longer duration time, especially in the later stage, which has become a long-term channel for shale gas escape. Comprehensive analysis shows that there are many detachment layers in the Dahongshan thrust belt, and the thrust and deformation destroyed multi-layer shale gas reservoirs and conventional gas reservoirs.

Geological conditions and controls of gas content of Carboniferous shale gas reservoirs in western Guizhou

JIANG Bingren, DENG Ende, YANG Tongbao, HAN Minghui, MA Zijie

2022, 44(4): 629-638. doi: 10.11781/sysydz202204629

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The Carboniferous Jiusi Formation is an important organic-rich shale stratum developed in Guizhou province, yet no breakthrough has been achieved for shale gas exploration and development. To study the geological conditions and controlling factors of shale gas accumulation in the Jiusi Formation, core and outcrop samples from the western Guizhou were analyzed using a series of methods, including organic geochemistry, XRD, FE-SEM, under overburden pressure, in-situ desorption and high pressure isothermal. The organic matters in the Jiusi shale are primarily type Ⅱ kerogen with a high organic carbon content, and are at the early stage of over maturity. Quartz and clays are the dominant minerals. The brittle mineral content is high, which is conducive to hydraulic fracturing. The reservoir is characterized by ultra-low porosity and permeability. There are mainly inter- and intragranular pores, organic pores, and micro-cracks. Small pore diameter, well-developed nano-scale pores, big specific surface area and total pore volume provide favorable conditions for shale gas enrichment and preservation. High in-situ desorption gas content (with an average value of 1.95 m³/t) and strong adsorption capacity (with a mean value of 3.10 m³/t) suggest good potential for shale gas. The adsorbed gas quantity is positively correlated with TOC, R_o, clay mineral content, porosity, specific surface area and total pore volume, and negatively correlated with average pore size.

Hydrocarbon accumulation characteristics and main controlling factors for Permian Maokou Formation in Yuanba area, Sichuan Basin

JIANG Zhili, ZHU Xiang

2022, 44(4): 639-646. doi: 10.11781/sysydz202204639

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A breakthrough has been made in the Permian Maokou Formation by the well of YB 7 in Yuanba area of the Sichuan Basin, which shows a great exploration potential. With continuous enrichment of data, it is necessary to strengthen the understanding of oil and gas laws and to summarize the main controlling factors of hydrocarbon accumulation, by which a basis for oil and gas exploration and deployment may be provided. In this paper, basic accumulation conditions and characteristics of gas pools in the Maokou Formation were studied, gas-source correlation and hydrocarbon charging time analyses were carried out, and some main controlling factors for hydrocarbon accumulation were summarized. The study area has favorable conditions for source rock and hydrocarbon preservation. The reservoir is mainly shoal superimposed karst fractured type. The gas pool is characterized by abnormally high pressure and high temperature. The natural gas is accumulated from both kerogen and crude oil cracking gas, mainly derived from the Wujiaping Formation. The oil and gas are largely filled in the Middle Jurassic, characterized by continuous filling. The hydrocarbon accumulation in the study area is mainly controlled by reservoir development, source rock conditions and hydrocarbon preservation conditions.

Geochemical characteristics and formation process of zebra dolomites in Lower Permian Qixia Formation, northwestern Sichuan Basin: a case study of well ST 18

WANG Lichao, ZHOU Yang, HU Linhui, ZHANG Ya, WANG Bozhi, QIAO Yanping

2022, 44(4): 647-654. doi: 10.11781/sysydz202204647

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Abundant natural gas resources are stored in the Lower Permian Qixia Formation of the Sichuan Basin. In recent years, great breakthrough for oil and gas exploration has been achieved in the Qixia Formation in the NW Sichuan Basin, and high-quality reservoirs mainly locate in dolomite strata. However, the origin of dolomites in the Qixia Formation is still unclear. Special zebra-textured dolomites were observed in the Qixia Formation from the cores of well ST 18. In this paper, a comparative study of the light and dark belts in the zebra texture was systematically carried out with petrological and geochemical methods. Results show that the light belt is mainly composed of medium to coarse crystalline saddle dolomites and its cathodoluminescence is bright red, while the dark zone is composed of medium to fine crystalline dolomites and its cathodoluminescence is dark red. The δ¹³C values in light and dark zones are within the δ¹³C range of contemporary seawater, while the δ¹⁸O values are more negative than those of contemporary seawater. It is then indicated that the dolomitization fluid was derived from seawater and the oxygen isotopes were fractionated by the affection of high temperature. The order degrees of dolomites in the light and dark zones are consistently high. It was speculated that the order degrees of dolomites in the light and dark zones had been matured to the same degree during the later burial stage. In addition, the occurrence of pyrite confirmed the involvement of hydrothermal fluids in the formation of dolomites. Therefore, the formation of zebra dolomites in well ST 18 mainly went through the following three stages: (1) Fluids dissolved and dolomitized primary limestones along tectonic fractures to form medium to fine crystalline dolomites in the dark zone; (2) Hot fluids precipitated to form medium to coarse crystalline saddle dolomites in the light zone; (3) The order degrees of dolomites in the dark and light zones had adjusted to the same degree in the later deep burial stage.

Differential hydrocarbon accumulation and its influence on the formation of gas reservoirs in the Longwangmiao Formation, central Sichuan Basin

LIN Tong, TAN Cong, WANG Tongshan, LI Qiufen, FENG Mingyou, HUANG Shiwei, DONG Jinghai

2022, 44(4): 655-665. doi: 10.11781/sysydz202204655

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The Longwangmiao gas reservoirs have significant differences in various structural positions in the Anyue gas field of the Sichuan Basin including diversities of pressure system, gas-water interface, bitumen content and charging time. By determining the diagenetic sequence of rocks and minerals, analyzing inclusion components by Raman spectrum, calculating capture temperature, and restoring regional tectonic evolution process, comparative analyses of the charging evolution process of liquid and gas hydrocarbon were carried out. Results show that (1) Three distinct pressure systems exist in gas reservoirs in the central Sichuan Basin. Gas-bearing zones and water-bearing zones separately distributed. The average pressures of gas reservoirs decrease gradually from north to south, and the three pressure systems have independent gas-water interfaces. (2) The initial charging temperatures of hydrocarbons varied in different gas bearing systems.The temperature during liquid hydrocarbon charging was higher in the west and lower in the east, and the accumulation evolution process was different from west to east. The charging temperature during liquid hydrocarbon cracking of gaseous hydrocarbon was higher in the east and west, and slightly lower in the middle. Based on the division of pressure zones of the Longwangmiao gas reservoir and the determination of gas-water boundary value, the distribution range of effective gas reservoirs was predicted for different gas-bearing systems, which provided guidance for further exploration and deployment.

Pore characteristics of marl reservoir in Maokou Formation of Middle Permian, southeastern Sichuan Basin

HAN Yueqing, LI Shuangjian, HAN Wenbiao, ZHAO Hongqin, LIU Guangxiang, HAO Yunqing

2022, 44(4): 666-676. doi: 10.11781/sysydz202204666

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Breakthroughs of oil and gas exploration have recently been achieved via several wells in marl reservoirs of the first member of the middle Permian Maokou Formation in the southeastern Sichuan Basin. As a new type of unconventional gas reservoir, a lot of attention was attracted. In order to understand lithological characte-ristics and pore characteristics of marl reservoirs, lithological, pore types and pore structure characterization, works were carried out based on field and core samples. Results show that: (1) The TOC content of the marl reservoirs, which is mainly in outer gently sloping facies, is 0.76%-1.1%, with an increasing trend from northwest to southeast, similar to porosity changes. (2) Reservoir spaces of the marls mainly include organic pores, inorganic pores and microfractures. The organic pores can be classified into independent organic pores, organic pores with talc and intergranular organic pores of pyrite. The inorganic pores can be classified into intergranular pores, intercrystalline pores, and crystal dissolved pores. The microfractures can be classified into talc fractures, grain boundary fractures, and stress fractures. Organic pores are not dominant in the marl reservoirs, while microfractures are the most important reservoir space. (3) Combined characterization of cryogenic nitrogen adsorption, cryogenic CO₂ adsorption, high-pressure Hg injection experiments and CT scan show that pores of the marls are mainly ink-bottle shaped with narrow neck and wide body. Micropores, mesopores and macropores are developed, with pore diameters of about 0.4-100 nm. The marls have obvious lithologic heterogeneity and poor connectivity. Fractures have an important influence on the connected pores. The marl in the first member of the Maokou Formation is a new type of unconventional reservoir, which has complex mineral composition and special pore characteristics. Targeted acid fracturing technology should be strengthen to promote the exploration and production of the marl reservoir.

Geochemical characteristics of reservoir bitumen and its relationship with hydrocarbon evolution in well SHB1-X-3, Shunbei No.1 fault zone, Tarim Basin

XU Jin, WU Xian, ZHU Xiuxiang, CHEN Qianglu, YOU Donghua, XI Binbin

2022, 44(4): 677-686. doi: 10.11781/sysydz202204677

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Three sections of fracture-cave filling bitumen with a total thickness of approximately 3.25 m were discovered between 7 265 m and 7 275 m in Ordovician Yijianfang Formation micrites in the well SHB1-X-3, Shunbei No.1 fault zone, central Tarim Basin. In this paper, detailed organic petrological and geochemical analyses were carried out on solid bitumen and related extracts. The matrix minerals and argillaceous belts within micrites showed obvious fluorescence characteristics. The fractures of micrites are filled with gas-liquid hydrocarbon inclusions in calcite and quartz veins. The above occurrence relationship shows that there are at least two stages of hydrocarbon charging, and bitumen and gas-liquid hydrocarbon inclusions are the products of hydrocarbon charging in the early and late stages, respectively. Geochemical characteristics of the extracts of bituminous limestones and the crude oil in Shunbei No.1 fault zone indicate that the biogenic conditions of bitumen and crude oil are similar, both of which come from marine decay under reducing environment. The Cambrian Yu'ertusi mudstones with algae as the main hydrocarbon source may be the major source rocks of bitumen and crude oil discovered. The proportion of crude oil cracked gas in the current oil and gas reservoirs is very low. It is speculated that the contribution of cracked gas to the current oil and gas reservoirs is limited.

Hydrocarbon generation simulation of coaly source rocks in the Lower combination on the southern margin of Junggar Basin and indications for oil and gas sources of well Gaotan 1

YU Miao, GAO Gang, JIN Jun, MA Wanyun, HE Dan, XIANG Baoli, FAN Keting, LIU Miao

2022, 44(4): 687-697. doi: 10.11781/sysydz202204687

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With the deepened exploration progress in the Junggar Basin, the lower assemblage has increasingly become the focus for oil and gas exploration. However, systematic research has not been achieved on the hydrocarbon generation characteristics of the lower assemblage source rocks, and systematic experimental analysis has not been carried out on the hydrocarbon generation potential and oil and gas generation capacity of coaly source rocks with different lithology. Oil and gas have highly yielded in the well of Gaotan 1 in the Gaoquan anticline, and which lithology of coaly source rocks have the closest relationship with it is worth for a further discussion. Sealed vessel autoclave hydrous simulation of Jurassic coaly rock, carbonaceous mudstone and mudstone was carried out in this study, results show that carbonaceous mudstone and mudstone have high oil generation potential. Carbonaceous mudstone is the main contributor of Jurassic coal formed oil, and cutinite may be the main oil source in carbonaceous mudstone. Coaly rock has higher gas generation potential than carbonaceous mudstone and mudstone in higher evolution stage, mainly generating kerogen cracking gas. The carbon isotopic fractionation of simulated gas appears in vary degrees with the increase of evolution, that is, with the increase of maturity, the stable carbon isotope of gas first becomes lighter and then becomes heavier, and the δ¹³C₁ fractionation is more obvious than that of δ¹³C₂. Combined with simulation experiments, the oil and gas source of well Gaotan 1 was further analyzed. It was then concluded that the crude oil of Cretaceous Qingshuihe Formation in well Gaotan 1 is mainly high-mature crude oil generated by Jurassic carbonaceous mudstone, and the three lithologic coaly source rocks contributed to natural gas.

Co-evolution simulation experiment of source rock fluid and reservoir rock and its geological implications: a case study of Upper Triassic Xujiahe Formation, western Sichuan Basin

MA Jianfei, MA Zhongliang, MIAO Jiujun, ZHENG Lunju, WANG Qiang, HE Chuan

2022, 44(4): 698-704. doi: 10.11781/sysydz202204698

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Fluid-rock interaction is critical for the formation of tight sandstone reservoirs, contributing to illustrate the distribution of high-quality reservoirs. In this study, a simulation experiment on the co-evolution of type Ⅲ source rock fluids and feldspar-quartz sandstone reservoirs under sealed condition was carried out with the samples from the Upper Triassic Xujiahe Formation in the western Sichuan province. A large amount of CO₂ generated leads to the development of carbonate cements in sandstone reservoirs at temperature of~140 or 170℃, indicating the main factors for sandstone reservoir densification. The retention effect of hydrocarbon fluids plays a key role for reservoir densification. In the closed diagenetic system, tight oil and gas exploration should focus on locating favorable sedimentary sand bodies that are conducive to the formation and preservation of primary pores; while in a semi-open or open system, it should be directed to reservoirs with secondary pores in the dominant migration and accumulation areas of acid fluids.

Application of laser Raman spectroscopic parameters of coal maceral analysis with different maturity

GAO Zhiwei, ZHANG Cong, LI Meijun, FANG Ronghui, BORJIGIN Tenger, XIAO Hong, ZHU Zhili

2022, 44(4): 705-711. doi: 10.11781/sysydz202204705

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Laser Raman spectroscopy has shown a good application prospect for maceral analysis. Raman spectroscopic analysis of different macerals (e.g., vitrinite, semifusinite and macrinite) in coal samples with different maturity (%R_o=0.49%-1.88%) was carried out in this study, and results show that three macerals have significantly different Raman spectrum parameters, which have the following implications for the macerals analysis of coal: (1) Macerals in coal samples can be distinguished by the combination of Raman spectrum parameters. There are 21 kinds of parameter combinations discussed in this study, which can be used as reference standard for the classification of these organic macerals; (2) Peak displacement (W_D1) is the most critical parameter to distinguish the macerals of coal samples. The influence of thermal evolution should be considered, which may assistant for the study of maceral differences in the Lower Paleozoic which are in the high to over mature stage with optical properties gradually converging. Therefore, Raman spectrum parameters can be used as an effective method for maceral analysis.

Evaluation of oil content in shale by sealed thermal desorption: a case study of Jurassic Da'anzhai Member, Sichuan Basin

LUO Chao, ZHANG Huanxu, ZHANG Jizhi, SHI Xuewen, XU Zhiyao, ZHANG Yu, WU Wei

2022, 44(4): 712-719. doi: 10.11781/sysydz202204712

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The oil content in shale is still a contentious issue due to the evaporative losses of free hydrocarbon. Considering the objective of the evaluation of oil content in shale and the demand of fast analysis at wellsite, a newly developed sealed rock thermal desorption method is introduced to quantify the content of free hydrocarbon in rock samples which combined the technique of sealed crushing at low temperature and improved the traditional rock pyrolysis (Rock-Eval). Comparison experiments have been conducted on Jurassic Da'anzhai shale from the Sichun Basin. The S₀ value ranges from 0.001 to 0.046 mg/g, with S₁ value from 0.165 to 4.648 mg/g by routine method of rock pyrolysis. The S₀ value by the sealed thermal desorption method, which ranges from 0.026 to 0.984 mg/g, is about 1-2 order of magnitude higher than that of Rock-Eval. By improving the heating program, the sealed thermal desorption method can obtain the hydrocarbon content per unit mass of rock at temperatures of 5, 5-90 and 90-300℃, which not only obtains abundant oil-bearing data, but also shortens detection time. Combined with parameters such as mud gas measurement, shale geochemical parameters, and reservoir fluid properties, the "sweet spots" of shale oil in the Da'anzhai Member of the study well were evaluated, providing a new experimental method for evaluating the oil content of shale oil.

Mechanical properties and fracturing characteristics of tight sandstones based on granularity classification: a case study of Permian Lower Shihezi Formation, Ordos Basin

ZHAO Ning, WANG Liang, ZHANG Lei, SIMA Liqiang, LIU Zhiyuan, WEN Dengfeng

2022, 44(4): 720-729. doi: 10.11781/sysydz202204720

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Tight sandstone reservoirs of the Lower Shihezi Formation in the Ordos Basin are characterized by poor physical properties, abnormal formation pressure, and the development of high-strength interlayers, etc. Thus, the selection of mechanical parameters and the fracturing characteristics of the reservoirs are significant for the effective development of oil and gas fields. For the tight sandstone samples from the Lower Shihezi Formation in the Hangjinqi area of the Ordos Basin, we carried out parallel experiments to test tensile strength, and to make triaxial mechanical experiments with high temperature and high pressure of in-situ conditions. Based on granularity classification, the mechanical strength properties and fracturing characteristics of tight sandstones were discussed. The tight sandstones in the Lower Shihezi Formation can be classified as medium- to fine-grained lithic sandstones, coarse-grained lithic sandstones, and giant- to coarse-grained lithic sandstones. The coarser the particle size, the better the physical properties, and the higher the quartz content, the lower the clay content. As particle size increases from fine to coarse, the mechanical strength and elastic parameters gradually decrease, and the ability of rock to resist deformation and maintain structural integrity decreases. The fracturing of the samples show the characteristics of brittleness to matrix mixing. Under the same stress and construction conditions, different rock types will result in various reservoir fracturing difficulty and stimulation effects. Different engineering mechanic parameters should be selected according to actual formation conditions.

Shale oil size distribution models and their sensitivities

LU Zhendong, LIU Chenglin, ZENG Xiaoxiang, YANG Hong, ZANG Qibiao, WU Yuping, LI Guoxiong, FENG Dehao

2022, 44(4): 730-738. doi: 10.11781/sysydz202204730

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With the rapid development of unconventional oil and gas resources, the demand for corresponding evaluation methods is increasing. At present, the evaluation methods for unconventional oil and gas resources are divided into analogy, statistical and genetic method. While constantly innovating evaluation methods, how to improve conventional methods and apply them to unconventional resource evaluation is also a focus and difficulty in current research. Taking a well as an unit and the EUR of the well as the unit's oil or gas reserves, a Pareto distribution model was established, and a program was compiled according to the principle of random sampling and skew sampling to analyze the sensitivity of number N, shape parameter and exploration coefficient E to the model. This method was applied to the shale oil resource evaluation in the X230 well block in Heshui area of Ordos Basin. Results show that the number of discoveries affects the size and dispersion of the parameters for oilfield distribution. The distribution model tends to be stable when the number is more than 300. Exploration coefficient has little influence on the sensitivity of distribution model, which is the limitation of taking EUR as evaluation unit. According to the variation of number N with shape parameter β, the number corresponding to cut-off point can be determined, that is, the sum of EUR of all wells is the recoverable resource of the area, which is 6.72×10⁶ t. The result is consistent with the evaluation of oil and gas resource abundance. This method can provide guidance for unconventional oil and gas resources evaluation.

Prediction model of TOC contents in source rocks with different salinity degrees based on Support Vector Machine (SVM)

CHU Yongzhi, LIU Chenglin, TAI Wanxue, YANG Hong

2022, 44(4): 739-746. doi: 10.11781/sysydz202204739

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Abstract:
The total organic carbon (TOC) content is an important parameter for the evaluation of abundance of organic matter in source rocks, and its predicting accuracy is of great significance to oil and gas exploration and development. At present, TOC prediction is mainly based on statistical analysis methods such as ΔlogR method and multiple regression analysis, problems such as weak generalization ability and strong subjectivity exist. The introduction of machine learning methods can effectively solve these problems of instability, nonlinearity, and high complexity. However, current research remains at the level of method comparison and selection with no indepth analysis of good models and their applicability. In this paper, a Support Vector Machine (SVM) model with better application effects was used to predict TOC contents of source rocks with different salinity degrees. As source rocks of freshwater lacustrine facies, the Paleogene Dongying Formation in the Bozhong Sag of Bohai Bay Basin and Paleogene source rocks in the Shizigou area of the western Qaidam Basin as saline lacustrine facies source rocks were selected to test and compare the effectiveness of the model. Through correlation analysis and XGBoost feature importance analysis, the logging sonic differential time (DT), volume density (DEN), spontaneous potential (SP), Gamma ray (GR) and depth were selected as the input layer, while the TOC was used as the output layer to establish a TOC prediction model based on SVM. Results show a strong generalization ability when applied to different sedimentary environments. It can adapt to the geological characteristics of different regions. The sensitivity of logging curves to the abundance of organic matter in source rocks varies in different sedimentary environments, which makes the model more relevant when applying to the fresh water lacustrine facies area in the Bohai Bay Basin.

2022, 44(4): 747-747.

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Abstract:

2022 Vol. 44, No. 4

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