石油实验地质

2024, 46(1): .

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Technical system and achievements of rolling exploration in large and medium-sized deep-water gas fields: a case study of marginal gas field A in central canyon of Qiongdongnan Basin

CHEN Kui, HU Desheng, SONG Ruiyou, GONG Yu, XIAO Dazhi, HUANG Anmin, ZHU Yushuang

2024, 46(1): 1-10. doi: 10.11781/sysydz202401001

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A complete technical system of gas field rolling exploration such as target search, evaluation and drilling was introduced to promote the development of the deep-water marginal gas field A in the central canyon of the Qiongdongnan Basin. In addition to the traditional target search technology of oil and gas potential in the zone, a target search technology of evaluation process was proposed for the marginal gas field A. A total of five potential oil and gas blocks were searched, and the structure A4 was selected for oil and gas target evaluation. The main controlling factors of hydrocarbon accumulation in the structure A4 were studied from two aspects: trap interpretation and implementation, and trap hydrocarbon detection. The predicted dominant gas-bearing areas in the central part of structure A4 have favorable gas-bearing information characteristics such as strong amplitude attributes, low density, low velocity, low P-wave impedance, and low P-wave and S-wave velocity ratios. They were generally classified as class Ⅲ AVO anomaly, which can upgrade the HL_0 gas group to control natural gas geological reserves. The rolling exploration well A4-1 was drilled, encountering a gas layer of over 20 m in the Huangliu Formation, and a suspicious gas layer of nearly 10 m in the second member of Yinggehai Formation. The proven geological reserves of natural gas were nearly 3 billion cubic meters, and the drilling effect was good. The application of rolling exploration research in the deep-water marginal gas field A not only effectively promotes the subsequent rolling exploration activities of the marginal gas field A, but also confirms that rolling exploration is also applicable to deep-water oil and gas exploration.

Shale oil reservoir characteristics and exploration implication in Da'anzhai Member of Jurassic Ziliujing Formation in central Sichuan Basin

HONG Haitao, LU Jungang, QIN Chunyu, ZHANG Shaomin, ZHANG Rui, ZHOU Yixin, XIAO Zhenglu, ZHOU Hongfei, HAN Luyuan

2024, 46(1): 11-21. doi: 10.11781/sysydz202401011

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To further guide the exploration and development of shale oil in the Da'anzhai Member of the Jurassic Ziliujing Formation in the Sichuan Basin, it is urgent to clarify the favorable lithofacies of shale oil. In this study, core observation, thin section authentication, high pressure mercury injection, NMR, rock pyrolysis analysis and other experiments were used to analyze the reservoir space types, pore structure characteristics and oil-bearing properties of different lithofacies of shale series in the Da'anzhai Member. The results show that mainly six types of lithofacies are developed in the Da'anzhai Member: massive (argillaceous) shell limestone, layered argillaceous shell limestone, layered shell shale, laminar shell-bearing shale, massive shell-bearing clay shale and foliated siltstone-bearing clay shale. The physical properties of shale in the Da'anzhai Member are much better than those of shell limestone, and with the increase of calcareous content, the pore size of the shale gradually increases, but the total pore volume and total connected volume gradually decrease. The average free oil value (S₁) of the shale series in the Da'anzhai Member is 1.31 mg/g, with moderate oil-bearing property. The S₁ values of the foliated siltstone-bearing clay shale and the laminar shell-bearing shale are relatively higher, which are 2.37 mg/g and 1.82 mg/g, respectively. In summary, it is believed that the foliated siltstone-bearing clay shale and the laminar shell-bearing shale have good reservoir properties and high oil-bearing properties. The lithofacies combination of the two can be a key exploration target for shale oil in the Da'anzhai Member.

Geological characteristics and controlling factors of lithologic reservoirs in southwestern Qaidam Basin

WU Yanxiong, XUE Jianqin, SHI Qi, YANG Yun, LIU Junlin, MA Fengchun, LI Xiang, WANG Yanqing

2024, 46(1): 22-31. doi: 10.11781/sysydz202401022

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In recent years, several small and rich lithologic oil and gas reservoirs have been discovered in the saline lacustrine beach bar sand in the Qaidam Basin. In order to expand the exploration scale of lithologic oil and gas reservoirs, find new exploration targets and zones, and increase storage and production of oilfields, based on coring, logging and seismic data, the controlling factors of oil and gas accumulation in lithologic reservoirs are defined, and some exploration succeeding fields of lithologic reservoirs are pointed out. The results show that: The southwestern Qaidam Basin has four favorable conditions for the formation of lithologic reservoirs. The first is the development of three stable ancient slopes, namely, the Qigequan-Hongliuquan, Shaxi-Yuejin, and Zahaquan-Wunan, which are inherited and conducive to the accumulation of oil and gas. The second is the proximity of two hydrocarbon generation centers, Hongshi and Zahaquan, with superior oil source conditions. The third is that the salt lake basin developed large braided river delta, widely distributed shoal-bar sand and algal hill-gray cloud flat deposits, forming two complementary types of reservoirs of clastic rock and carbonate rock. The fourth is the development of a variety of drainage systems, which can form several sets of oil-bearing strata vertically. Controlled by paleo-structural, sedimentary and diagenetic factors, there are four types of lithologic reservoirs in the southwestern Qaidam Basin: updip pinching out, sandstone lens, physical sealing and dolomitization trap. Lithologic reservoirs are controlled by three factors: paleo-structure, high-quality source rock and effective reservoir. Paleo-structure determines the type of lithologic traps and the direction of hydrocarbon migration. The high-quality source rock controls the distribution and scale of lithologic reservoirs and effective reservoir controls the accumulation of lithologic reservoirs. Comprehensive evaluation shows that the braided river delta front sand body is a favorable area for the exploration of lithologic reservoirs in the lower Ganchaigou Formation of the Lower Paleogene, mainly distributed in the basin dip end of Shaxi, Gasi, and Wunan. The dolomitization trap is a favorable area for exploration of lithologic reservoirs in the upper member of lower Ganchaigou Formation of Paleogene, mainly distributed around the Hongshi Sag. The widely distributed beach bar is a favorable area for lithologic oil exploration in the upper Ganchaigou Formation and lower Youshashan Formation of Neogene, mainly distributed in Yingxiongling, Gasi, Zhahaquan, Wunan, and other areas. This understanding supports a series of major breakthroughs in lithologic exploration, such as well Qietan 2 and the new series of Gasi, with important guiding significance for further exploration of lithologic reservoirs in the southwestern Qaidam Basin.

Micro characteristics and formation mechanism of low-quality gas reservoirs in Taiyuan Formation of Shenmu Gas Field, Ordos Basin

ZHANG Tao, GONG Xiaoke, HUANG Chao, CAO Qingyun, MENG Fengming, DONG Zhanmin, CHEN Zhaobing, WANG Hengli

2024, 46(1): 32-45. doi: 10.11781/sysydz202401032

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Shenmu Gas Field in Ordos Basin shows the characteristics of low quality gas reservoir, and its deve-lopment effect is quite different from that of surrounding gas fields, which brings some problems to the exploration deployment and sustainable production of the gas field. In order to reveal the origin of low-quality gas reservoirs, the microscopic characteristics and formation mechanism of Taiyuan Formation reservoirs in Shenmu Gas Field were studied based on microscopic experiments at different scales. The results show that the reservoir of Taiyuan Formation in Shenmu Gas Field is characterized by "rich in quartz, poor in feldspar, and high content of rock detritus". The reservoir of Taiyuan Formation is a low porosity and ultra-low permeability tight sandstone reservoir with small pore-fine throat combination, poor pore throat connectivity, and weak reservoir permeability. The formation of low-quality reservoirs in Taiyuan Formation is affected by the matrix, the content of rock detritus in eruptive rocks and diagenesis. During the late Carboniferous to early Permian, the formation of the reservoir was significantly affected by the volcanic activity of the Inner Mongolia ancient uplift in the north of the Ordos Basin. The content of matrix and rock detritus of the eruptive rock in the sandstone was generally high. The rock detritus of the eruptive rock provided the main material basis for the development of secondary pores. While the matrix blocked the pores, it also produced a certain number of matrix dissolved pores, which had a dual impact on the reservoir. The dissolution during diagenesis is critical to the formation of Taiyuan Formation reservoir, and the increased porosity accounts for 64.3% of the current porosity. At the end of the Late Cretaceous, the late Yanshan movement led to the structural inversion of the Ordos Basin, the readjustment of gas and water, and the escape of natural gas along the fault in the eastern part of the basin. Finally, the low quality gas reservoir of Taiyuan Formation in Shenmu Gas Field is formed. The next exploration focus of Shenmu Gas Field should be based on the clear macro distribution law of diagenesis and favorable lithologic traps, and further search for the development area with high content of eruptive rock detritus and low content of matrix.

Reservoir-forming rules and main controlling factors of Archean buried hill reservoir of middle to northern Liaoxi Uplift in Liaodong Bay area in Bohai Bay Basin

GUO Longlong, WANG Jun, ZHANG Chunguang, CHEN Hongde

2024, 46(1): 46-53. doi: 10.11781/sysydz202401046

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The Bohai Bay Basin is one of the key areas for the exploration of buried hill oil and gas resources in China. In order to create a new prospect for the exploration of the Archaean buried hills in this area, the reservoir-forming laws and main controlling factors of the Archaean buried hill reservoir in the Liaodong Bay area were studied. Based on drilling data such as stratum, logging, and seismic data, this paper classified the lithology and distribution patterns of Archean buried hills in the Liaodong Bay area, and analyzed the dominant reservoir space types and controlling factors. The results show that the Archean buried hills in the Liaodong Bay area are composed of schist, metamorphic granite and cataclastic rocks, with schist being the predominant lithology. The current structure is high in the south and low in the north. The strata are relatively intact in the north, while the upper part of the strata in the south shows evidence of denudation. The proportion of igneous rocks increases gradually from north to south. The metamorphic rocks are dominated by fracture reservoirs. The content of mafic minerals is inversely correlated with the brittleness of rocks. Tectonic deformation led to fracture development. Three sets of structural fractures were developed in the Archean buried hills of the Bohai Bay Basin, i.e., NNE shear fractures and SN tensile fractures were developed in the stress directions of NE strong shear and SN strong compression in the early Yanshanian period, NE shear fractures and NE tensile fractures were developed in the stress directions of NW strong extension and NE weak shear in the early Himalayan period, and EW tensile fractures and NE and NW conjugate shear fractures were developed in the stress directions of NE strong shear and NW weak extension in the late Himalayan period. The degree of regional tectonic activity controlled the effectiveness of the fractures. The Yanshanian movement was the main stage of fracture formation in metamorphic rock reservoirs. During the Himalayan period, fractures were mainly filled and semi-filled with calcite, and effective fractures could be formed through dissolution in the later stage.

Characteristics and genetic mechanism of salt structure in Fuxingchang anticline, Jiangling Sag, Jianghan Basin

QIU Jianhua, PENG Jinning, TANG Wei, PAN Wenlei, LI Fengxun, YANG Fan

2024, 46(1): 54-63. doi: 10.11781/sysydz202401054

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The Fuxingchang salt anticline is an important oil-bearing structure in the Jiangling Sag of the Jianghan Basin, while its structural evolution and formation mechanism are unclear, which restricts the delicate exploration of oil and gas. Therefore, the analysis of structural evolution and formation mechanism of the Fuxingchang salt anticline is not only helpful to understand the influence of salt bed flow under different stress backgrounds on the formation and evolution of the anticline, but also important to understand the process of petroleum accumulation. The structural characteristics and genetic mechanism of Fuxingchang anticline were studied by analyzing 3D seismic data and combining with the techniques of balance restoration of key structural layers and growth strata analysis. The results show that the Fuxingchang anticline is a salt anticline with significant structural features that vary along strike, resulting from multiple stages of fault reconstruction and complex deformation mechanisms. The anticline was initially formed during normal faulting in the sedimentary period from Early Eocene Xingouzui Formation to the early period of Late Eocene, which formed roller fold and caused the accumulation of salt layer. From the late period of Late Eocene to Oligocene, the differential loading of sedimentary strata drove salt beds to flow from west to east, resulting in the westward dip of the whole structure and the formation of monoclinal structure, which was uplifted and denudated in the late period of Oligocene. The anticline was finalized from Neogene to Quaternary, and evolved into a compressional salt anticline, associated with reverse faults and kink-band structures. The formation and evolution of Fuxingchang anticline are influenced by the combined effects of regional stress background, salt layer of Shashi Formation, the east-dipping normal faults, sub-salt paleostructures, etc. The structural trap formed by Fuxingchang salt anticline occurred slightly earlier than the main oil expulsion period of source rocks, and during the main oil expulsion period, the structure was in the depression stage, with weak fault activity, which was conducive to the early accumulation of trapped oil and gas.

Geological characteristics and sweet spot selection of Permian organic-rich sedimentary tuff series in northern Fuling, Chongqing

DONG Qingyuan, XU Xuhui, LI Guofa

2024, 46(1): 64-74. doi: 10.11781/sysydz202401064

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The sedimentary tuff in the second member of Permian Wujiaping Formation in the northern Fuling area of Chongqing is a new type of organic-rich source rock, which is a new field of unconventional gas reservoir exploration. Clarifying the distribution of key sweet spot parameters of the sedimentary tuff series in the second member of Wujiaping Formation is a primary issue in exploration and evaluation. Based on drilling, logging, experimental analysis and seismic data, this paper evaluated the target sweet spot starting from the sedimentary tuff series' organic geochemistry, lithological characteristics, thickness distribution, formation pressure, fracture development and other geological conditions for reservoir formation and enrichment, and focusing on the two key factors of lithology quality and compressible fracture network. The results show that: (1) The sedimentary tuff series in the second member of Wujiaping Formation in the northern Fuling area is in the deep-water shelf facies, with high organic matter abundance. The TOC content is mainly 5%-6%, the R_o value ranges 1.90%-2.44%, the organic matter types are mainly Ⅰ and Ⅱ, and the thickness of high-quality sedimentary tuff section (TOC≥4%) is 15-20 m, with a wide distribution area. (2) The reservoir space of the high-quality sedimentary tuff section is diversified, the porosity is high, the brittle mineral content is high, the formation pressure coefficient is high to ultra high pressure level, and small-micro fracture zone is developed at the hinge zone, reflecting a good gas exploration potential of "self-generation and self-storage". (3) The sedimentary tuff gas reservoir in the second member of Wujiaping Formation in the northern Fuling area has the laws of high quality control of enrichment, overpressure control of reservoir and fracture network control of sweet spot. The sweet spot evaluation criteria for sedimentary tuff series in the second member of Wujiaping Formation are preliminarily established in combination with the main control factors, and three target sweet spots are selected, with an area of 186.4 km². The L2-L1 well area in the northwest of the exploration area has good oil and gas shows, which can be a favorable target for recent exploration.

Uplifting and exhumation history in Southern Qiangtang Depression of Qinghai-Tibet Plateau since Cretaceous: constrain from low-temperature thermochronology

MA Zeliang, HE Zhiliang, LUO Kaiping, PENG Jinning, ZHUANG Xinbing, YANG Fan, LIU Xu

2024, 46(1): 75-86. doi: 10.11781/sysydz202401075

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The uplifting and exhumation history of the Southern Qiangtang Depression was studied for reconstructing the evolution of the Qinghai-Tibet Plateau and evaluating the oil-gas preservation conditions in the Qiangtang Basin. Samples of Jurassic sandstone from Gaeraobao area in the center of Southern Qiangtang Depression were analyzed using zircon and apatite (U-Th)/He and apatite fission track (AFT) techniques, and the data showed that most grains experienced a full annealing phase. Based on the inversion of the thermal history of the basin from the experimental data and combined with the study of regional low temperature thermochronology, it is believed that the Southern Qiangtang Depression has experienced three major uplifting and exhumation episodes: the Early Cretaceous, the Paleocene-Eocene and since the Miocene, and experienced exhumations of 1.7-2.6 km, 1.89 km, and 1.13 km, respectively in the center of Southern Qiangtang Depression. And the thermal history showed that the center of Southern Qiangtang Depression suffered exhumation first in the Early Cretaceous, and then the denudation gradually spread to the north and south. The three episodes correspond to the collision between Qiangtang and Lhasa terranes, the collision between Indian and Asian plates and the movement of N-S strike fault under the continuous convergence of the Indian and Asian continents, respectively. The thermal history of samples at different tectonic locations in the Southern Qiangtang Depression showed that they have undergone different exhumation processes, which may have been controlled by the different activity of regional N-S faults caused by the collision between Indian and Asian plates and its subsequent continued convergence. Based on the differences of thermal histories of the samples at different tectonic locations, it suggested that the regional N-S faults activated since 65-45 Ma.

Petrological characteristics, reservoir property and oil-bearing potential of intrusive rocks in well Shaduo 1, Qintong Sag, Subei Basin

XIA Xiang, MA Xiaodong, HU Wenxuan, ZANG Suhua

2024, 46(1): 87-97. doi: 10.11781/sysydz202401087

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Igneous rock oil and gas reservoir has gradually become an important type of oil and gas reservoir, but the igneous rock reservoir is highly heterogeneous, the reservoir property varies greatly, and the study of reservoir genetic mechanism is unsubstantial, which has become the main bottleneck of igneous rock reservoir evaluation. Taking the intrusive rocks in the second member of Paleogene Funing Formation in the Qintong Sag, Subei Basin as the research object, through systematic core observation, thin section identification, electron probe analysis and testing and logging interpretation, the lithologic and lithofacies characteristics, reservoir characteristics and main controlling factors of reservoir development of the intrusive rocks in the second member of Funing Formation in well Shaduo 1 in the Qintong Sag were analyzed. The results show that the lithology of the intrusive rocks varies remarkably longitudinally, and the intrusive rock body is composed of multiphase intrusive rock, with diabase on the top, pyroxene monzonite in the middle and olivine gabbro at the bottom. The development of porosity varies, with diabase and pyroxene monzonite exhibiting low porosity, while olivine gabbro showing relatively higher porosity. Due to the superimposition of multiple intrusions and hydrothermal alteration, good reservoir spaces are formed, with predominant pore types being dissolution pores and structural fractures, accompanied by the development of shrinkage fractures. The main factors affecting the reservoir physical properties are lithology and hydrothermal fluid activity. Among them, dark minerals such as pyroxene in olivine gabbro are most easily altered, so dissolution pores are highly developed. Additionally, regional fault structures generate numerous structural fractures in many dense igneous rocks, effectively connecting the pore-fracture system of intrusive rock reservoir and providing channels through which magmatic hydrothermal fluids flow in the subsequent dissolution processes. Generally, the overall oil-bearing potential of the intrusive rocks encountered in well Shaduo 1 is poor. Sporadic fluorescence is observed in the lower intrusive rock layers, while the upper intrusive rock layers are essentially devoid of oil.

Research progress of microscopic percolation mechanism of shale oil

WANG Mingchuan, WANG Ran, YUE Hui, ZHANG Wei, WANG Fuyong, CHEN Zhiqiang

2024, 46(1): 98-110. doi: 10.11781/sysydz202401098

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Shale oil has become the focus of the exploration and development of unconventional oil and gas resources in the world, but its development faces many challenges. Aiming at the complex pore space, the unclear percolation mechanism, and the urgent need to explore research methods of shale oil, this paper systematically expounded the research status of microscopic percolation mechanism of shale oil in experimental methods and computational simulation, and discussed the existing problems and the development trend of future research from the perspective of pore-scale and core-scale. The results show that the combination of various experimental methods can well characterize the pore structure of shale, but the characterization of micro-scale and core-scale flow is still insufficient. The direct method represented by Lattice Boltzmann Method and the indirect method represented by pore network simulation are the main methods to study pore-scale flow mechanism, but the consideration of micro-scale effect needs to be improved. The study of core-scale flow mechanism is mainly to establish a percolation model considering boundary layer effect based on capillary bundle model and fractal theory. It is pointed out that the main future research direction is to fully consider the factors such as boundary adsorption/slip, density/viscosity heterogeneity, stress sensitivity, start-up pressure gradient of shale oil in micro-nano pores, realize multi-scale percolation mechanism coupling, and establish a mathematical model that can accurately characterize the multi-phase and multi-scale flow of shale oil.

Geochemical characteristics of crude oil and contributions to hydrocarbon accumulation in multiple stages in Tahe subsalt area

XU Qinqi, CHU Chenglin, GUO Xiaowen, LIU Yongli, ZHANG Li, LUO Mingxia

2024, 46(1): 111-123. doi: 10.11781/sysydz202401111

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The process of hydrocarbon accumulation in polycyclic superimposed basins often involves multistage crude oil charging, but not every stage of crude oil charging plays a significant role in the current hydrocarbon accumulation. Fluid inclusion methods can only provide constraints on the stages and time of crude oil charging, but cannot determine the contribution of each stage of crude oil charging for hydrocarbon accumulation. To study the contributions of different stages of crude oil charging for the reservoirs, the Ordovician carbonate reservoirs in the subsalt area, Tahe oilfield (Tahe subsalt area) were taken as an example. This study employed crude oil geochemistry, fluid inclusion analysis, fluorescence spectrum, and single well simulation analysis methods to systematically reveal the fluorescence characteristics of crude oil and hydrocarbon accumulation stages and time of the study area. The analysis of crude oil biomarker parameters indicates that the crude oil has the same parent material and was deposited in a marine weak reducing environment. By comparing the crude oil with the study area's source rocks, it was determined that all the crude oil was derived from the source rocks of the Lower Cambrian Yuertusi Formation. The aromatic methylphenanthrene index and methyldibenzothiophene parameters of crude oil serve as effective indicators for the quantitative evaluation of crude oil maturity. The calculated crude oil maturity (R_o) in the Tahe subsalt area ranges from 0.90% to 1.47%, and this may correspond to multiple stages of oil and gas charging. Based on fluorescence spectrum analysis of oil inclusions and homogeneity temperature and salinity measurements of associated saline inclusions in the Ordovician reservoirs in the Tahe subsalt area and the study area's burial history of single well burial history and thermal history simulation, it was determined that the oil reservoirs in the Tahe subsalt area experienced three stages of crude oil charging during the stages of middle Caledonian (420 Ma), middle Hercynian (318 Ma) and late Himalayan (10 Ma). By comparing the fluorescence spectrum parameters of crude oil and oil inclusions in these three stages, it is concluded that the late Himalayan is the primary stage of hydrocarbon accumulation in the Tahe subsalt area, making the largest contribution for the Ordovician reservoirs in the Tahe subsalt area.

Geochemical characteristics and sources of natural gas in Hangjinqi area of Ordos Basin

ZHANG Mai, SONG Daofu, WANG Tieguan, HE Faqi, ZHANG Wei, AN Chuan, LIU Yue, LU Zhengang

2024, 46(1): 124-135. doi: 10.11781/sysydz202401124

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In order to clarify the differences of characteristics and sources of natural gas in different zones in Hangjinqi area of Ordos Basin, the geochemical composition characteristics of natural gas in three major exploration zones in Hangjinqi area were compared and analyzed in detail by means of gas composition analysis and carbon isotope analysis, and sources of natural gas in different zones were discussed based on the differences in the process of gas accumulation in different zones. The results show that the natural gas of the study area has a high content of hydrocarbon gases (mainly methane), and the drying coefficients are mostly lower than 0.95, suggest-ing that the natural gas is dominated by wet gases. The non-hydrocarbon gases are mainly carbon dioxide and nitrogen, which have lower contents. The carbon isotopes δ¹³C₁, δ¹³C₂ and δ¹³C₃ of natural gas show a positive carbon series distribution, but there are differences among natural gas carbon isotopes compositions in different zones. The δ¹³C₁ value of natural gas in Shiguhao zone is the heaviest, and the δ¹³C₂ and δ¹³C₃ values of natural gas in Xinzhao zone are significantly heavier than that in the other two zones. The genetic analysis results show that the natural gas in the three regions of the study area is of organic genesis, showing the characteristics of coal-type gas (humus-type gas), and the main body is kerogen primary cracking gas, and the source rocks are in the stage of high-mature to over-mature thermal evolution. Combined with the results of gas-source correlation and geological background, it is inferred that the natural gas in Xinzhao zone is mainly derived from the underlying source rocks of Shanxi Formation, and the natural gas in Duguijiahan and Shiguhao zones is sourced from the source rocks of Taiyuan and Shanxi formations in the southern part of the fault, but Taiyuan source rocks contribute more.

Eocene sporopollen assemblage from Ramree Island, Myanmar and its palaeoenvironment significance

SHI Defeng, ZHU Youhua

2024, 46(1): 136-145. doi: 10.11781/sysydz202401136

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In order to support the oil and gas exploration in China-Burma cooperation block M and determine the age and sedimentary environment of the oil and gas bearing strata in Ramree Island of this block, a total of 10 source rock samples were collected for sporopollen analysis from the interval 2 562-2 844 m of well R-3 in Ramree Island, Burma. Abundant sporopollen fossils were found in each sample through observation, and 135 species attributable to 85 genera or undetermined species were identified. The sporopollen fossils in this interval are rich in Momipites and Quercoidites, with Sabalpollenites areolatus, a common molecule in Eocene, appearing intermittently, and characterized by Schizaeoisporites eocenicus. Based on the distribution patterns of sporopollen characteristic molecules and dominant genera and species, one sporepollen assemblage was recognized, namely Schizaeoisporites eocenicus-Quercoidites-Momipites-Sabalpollenites areolatus. By comparing the distribution ages of foraminifers and coccolithus nannofossils in the same interval, it was inferred that the age of sporepollen assemblage was the middle to late Eocene. According to the characteristics of the sporepollen assemblage, the statistical results of Paleogene to Neogene sporopollen sequence data in China's oil and gas regions, three models for the classification of sporopollen plant types, temperature zones and dry and humid zones established after systematic research, and distribution characteristics of other palynological fossils, we interpret that the study area was offshore land paleoenvironment with subtropical and warm temperate humid paleoclimate in the middle to late Eocene.

Research on sedimentary environment and provenance for hydrocarbon source rocks of Upper Carboniferous Batamayineishan Formation in northeastern Junggar Basin: evidences from the geochemistry of mudstones

CAI Qianru, WANG Jinduo, ZHANG Guanlong, SONG Zhihua, WANG Shengzhu, XIONG Zhengrong, NI Shengli

2024, 46(1): 146-157. doi: 10.11781/sysydz202401146

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The distribution rules and hydrocarbon potential of source rocks are the major factors which determine oil and gas exploration in the northeastern Junggar Basin. Sedimentary background and environmental changes are the main factors controlling the genesis, distribution, and organic matter types of hydrocarbon source rocks. The main and trace elements and rare earth elements in sedimentary rocks are often influenced by palaeoclimate, paleo water chemical conditions, palaeoenvironment, and palaeosource during sedimentation process. Therefore, a comprehensive analysis of the distribution patterns of elements in sedimentary rocks can help to determine sedimentary environment and evolution process. The geochemical characteristics of major and trace elements and rare earth elements for mudstones of the Upper Carboniferous Batamayineishan Formation from outcrops of the north- eastern Junggar Basin were studied to reveal the sedimentary environment and the tectonic setting of the provenance, which can provide geological constraints for the origin and development conditions of hydrocarbon source rocks. According to a comprehensive analysis on chemical weathering indicators, element contents, and ratios between various major and trace elements, the mudstones of Batamayineishan Formation were deposited in a warm and humid paleoclimate background, and the deposition process was relatively stable in a shallow water with brackish-fresh features under oxidizing environment. Major and trace elements of mudstones indicate that the parent rocks are sedimentary rocks and felsic volcanic rocks and their provenance is derived from the weathering products of acidic igneous rocks of the Karamaili Island Arc, reflecting the tectonic transition from compression to extension during the post collision stage. The depositional environment and tectonic setting controlled the increased input of terrestrial higher plants, resulting in the medium abundance of organic matter with good hydrocarbon generating potential.

Quantitative evaluation of fault sealing by Weighted Shale Gouge Ratio(WSGR): a case study of Yongan area in Gaoyou Sag, Subei Basin

LI Chuhua, YU Wenquan, DING Jianrong

2024, 46(1): 158-165. doi: 10.11781/sysydz202401158

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The evaluation of fault sealing is an important part of analyzing hydrocarbon accumulation conditions in fault-block traps. Based on the improved Shale Gouge Ratio (SGR), this paper proposed a new method for evaluating fault sealing, Weighted Shale Gouge Ratio (WSGR). Firstly, the calculation parameters and influencing factors of SGR were analyzed using different geological models, and it is determined that fault distance, mud content, and mud rock distribution are important factors affecting shale smear. It was found that all muddy sediments that slide through the target reservoir have contributions to shale smear within fault distance, but the contributions of different points vary, with higher mud content and closer distances contributing more. Therefore, a new parameter called distance coefficient was introduced to represent the influence of mudstone distribution on shale smear. The distance coefficient is defined as the ratio of the difference between fault distance and the distance from mudstone to the target reservoir to the fault distance. Based on this, a calculation method named Weighted Shale Gouge Ratio (WSGR) was constructed, which is defined as the product of mud content and distance coefficient at each point, summed and divided by the sum of distance coefficients. The sealing performance of known oil and water layers in the upper oil and gas bearing system in the Gaoyou Sag is verified by using Weighted Shale Gouge Ratio (WSGR), and it is considered that when the value of WSGR is greater than 0.6, the fault has good sealing performance, thus determining the sealing discrimination criteria of this method. Finally, good application results have been achieved in the evaluation of fault sealing of Eocene Danan Formation in Yongan and other areas of the Gaoyou Sag.

Combined measurement of hydrogen sulfide content and sulfur isotope in natural gas

YANG Huamin, WANG Ping, TAO Cheng, WANG Jie, MA Liangbang

2024, 46(1): 166-172. doi: 10.11781/sysydz202401166

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Abstract:
The natural gas containing hydrogen sulfide in China has great exploration potential, and the origin, source and formation mechanism of hydrogen sulfide are of concern to petroleum workers. Hydrogen sulfide content and sulfur isotope analysis are two common and important identification indicators. Due to strong toxicity of hydrogen sulfide, many laboratories in China conduct fewer tests or cancel such testing items. In this paper, hydrogen sulfide conversion reagent is preferring selected in pretreatment process. At the same time, through improving isotope mass spectrometer supporting equipment, i.e. tuning the parameters of ion beam focusing of sulfur isotope Faraday cup, installing special chromatography column, Teflon pipeline, sulfur reaction tube, etc., the technology platform for combined measurement of hydrogen sulfide content and sulfur isotope is constructed. Secondly, the high purity sulfur dioxide standard gas is replaced with working standard gas of low concentration, low pressure and small volume, and the optimal experimental conditions are determined through system condition experimental exploration (stability, standard substance analysis, etc.). Finally, the solid precipitate generated by the reaction was sent into the mass spectrometer for the detection of sulfur isotope composition information, and the concentration of hydrogen sulfide in the gas to be measured is calculated by comparing signal with the isotopic composition of standard pure sulfur-containing substances. By using this method, the hydrogen sulfide content and sulfur isotope in some natural gas of Daniudi and Fuxian gas fields in Ordos Basin, and Hongxing area in western Hubei and eastern Chongqing are measured. The measured results are stable with good precision, and are consistent with the results of external laboratories. Comparing traditional method, this method can obtain sulfur content and sulfur isotope values by a single sampling. The preferred silver acetate reagent with one-step chemical method can reduce isotopic fractionation. In addition, the hydrogen sulfide inverting into solid silver sulfide are more reliable directly compared with the standard substance silver sulfide isotope. With low concentration, low pressure, small volume SO₂ as the working standard gas, it reduces the laboratory safety risk and instrument damage, and meets the environmental safety requirements.

Physical simulation experiment of tuffaceous dissolution effect in sandstone reservoirs: a case study of Paleogene Wenchang Formation in Huizhou and Lufeng area, Pearl River Mouth Basin

LI Xiaoyan, PENG Guangrong, DING Lin, YUAN Guanghui, ZHANG Qin, WU Qiongling, JIN Zihao

2024, 46(1): 173-182. doi: 10.11781/sysydz202401173

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Abstract:
Tuffaceous sandstone reservoirs of Paleogene Wenchang Formation in Huizhou and Lufeng area of Zhu I Depression, Pearl River Mouth Basin were selected, and core-scale fluid-rock interaction simulation experiments were designed and carried out to explore the dissolution and modification effect of acidic fluid on tuffaceous components in clastic reservoirs during burial process and its controlling factors. The dissolution characteristics and physical property response characteristics of sandstone reservoirs under different fluid flow rates and tuffaceous contents before and after the experiments were compared and analyzed through microscope observation, fluid composition analysis, physical property characterization and other methods. The results showed that tuffaceous dissolution was common in acidic fluid environment, but the intensity of tuffaceous dissolution and the response of reservoir physical properties were different under different experimental conditions. Among them, the openness and closure of diagenetic system determined the intensity of tuffaceous dissolution. Under the same rock and acidic fluid conditions, the amount of tuffaceous dissolution in the high flow rate open system was higher than that in the closed system, and the dissolution products in the closed system tended to precipitate, which was not conducive to the preservation of dissolution pores. In addition, the content of tuffaceous components significantly affected dissolution effect, the tuffaceous-rich sandstone would not be conducive to dissolution porosity, while the tuffaceous-containing sandstone and tuffaceous-poor sandstone could increase dissolution porosity, and tuffaceous-containing sandstone has higher dissolution efficiency. Overall, in the reservoirs with relatively moderate to low contents of tuffaceous components, the open diagenetic system in the shallow-middle burial stage is most conducive to the development of dissolution pores of tuffaceous components. After the late stage of acidic fluid dissolution and modification, it is easier to form secondary dissolution-type high-quality reservoirs. This study is of great significance for the prediction of dissolution-type reservoir sweet spots in different areas.

Preliminary application and prospect of well site determination technology of gaseous hydrocarbon in continental shale cores

JIA Mengyao, BAO Yunjie, LI Zhiming, SHEN Baojian, CAO Tingting, LIU Peng, YANG Zhenheng, LU Longfei, LI Maowen

2024, 46(1): 183-190. doi: 10.11781/sysydz202401183

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Fluid analysis of continental shale formations is an important basis for the evaluation of shale oil sweet spots. In view of the characteristics that gaseous hydrocarbons in core samples are easy to lose and the needs of shale oil drilling site, a device and method for rapid collection and determination of gaseous hydrocarbons in cores at well site are developed, and a rapid method for calculating apparent gas-oil ratio (AGOR) and estimating free oil loss based on gaseous hydrocarbon analysis and pyrolysis oil content analysis data of cores is discussed. The research shows that the device is suitable for the detection of gaseous hydrocarbons in full-diameter cores and bulk samples. It can not only realize the collection and determination of gaseous hydrocarbons in full-diameter cores at normal temperature and pressure, but also determine the total amount of gaseous hydrocarbons in bulk core samples. The relative error of gaseous hydrocarbon determination is 10%, and the test results can be converted into gaseous hydrocarbon content per unit mass of rock samples. The full-diameter core escape gas analysis can realize the non-destructive collection and determination of gaseous hydrocarbons in the cores, which reflects the change characteristics of vertical oil and gas bearing and heterogeneity of shale formations. AGOR can reflect the trend of oil-gas bearing and flowability of shale formations, and the higher AGOR, the better the flowability of shale oil of corresponding shale formations. AGOR can be used to estimate the loss of free hydrocarbon in the process of pressure and temperature reduction degassing, which has great application potential in establishing the recovery method of the loss of free hydrocarbon in the process of core temperature and pressure reduction degas-sing. The core gas hydrocarbon determination technology enriches the experimental technical means and methods of core fluid analysis suitable for well sites, and provides data support for fluid evaluation and sweet spot determination of continental shale formations.

Classification and evaluation of sweet spots of marine shale gas reservoir in Ordovician Wulalike Formation on the westen margin of Ordos Basin

ZHANG Linlin, WANG Kongjie, LAI Fengpeng, GUO Wei, MIAO Lili

2024, 46(1): 191-201. doi: 10.11781/sysydz202401191

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Sweet spot evaluation is of great significance for efficient exploration and development of shale gas reservoirs. Taking the shale reservoir in Ordovician Wulalike Formation on the western margin of the Ordos Basin as the research object, eight experiments including rock section analysis, X-ray diffraction, SEM scanning electron microscopy, low-temperature nitrogen adsorption, isothermal adsorption, total organic carbon (TOC) content test, organic matter vitrinite reflectance (R_o) test and triaxial rock mechanics test were carried out in this study. It is found that the rock type in the target area is gray brown mud shale, with the pore size in the ranges of 2-4 nm and 35-61 nm, and intergranular pores, clay mineral interlayer pores and intragranular pores are developed. The TOC content is 1.01%, the average R_o value is 1.75%, and the brittleness index is 47.8%. By analyzing the influence of different factors on the selection and evaluation of shale reservoir sweet spots, it is concluded that the content of siliceous minerals, clay minerals, pore specific surface area, TOC content and R_o value play a decisive role on the adsorption perfor-mance of the reservoir, the pore size and the number of pore types control the reservoir property, the content of brittle minerals and rock mechanics parameters affect the compressibility of the reservoir. According to the two indexes of adsorption property and reservoir property evaluated by geological sweet spots and the compressibility index of engineering sweet spots, the parameter indexes corresponding to different characteristics are finely classified, and a classification and evaluation scheme of geological sweet spots and compressibility sweet spots of the marine shale gas reservoir in Ordovician Wulalike Formation in the Ordos Basin is preliminarily established. The results show that all characteristic para-meters in the target area meet the grade Ⅱ standard. It could be a sweet spot for shale gas development.

Pore throat structure analysis and permeability prediction method of tight sandstone: a case study of Jurassic Shaximiao Formation in central Sichuan Basin

CHEN Shaoyun, YANG Yongqiang, QIU Longwei, WANG Xiaojuan, YANG Baoliang, Erejep HABILAXIM

2024, 46(1): 202-214. doi: 10.11781/sysydz202401202

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Subtle characterization of pore throat structure and permeability prediction of tight sandstone reservoir are the key for quality reservoir evaluation and development. Taking Jurassic Shaximiao Formation in central Sichuan Basin as an example, the pore throat structure is statically characterized by HPMI and fractal theory. The relations among pore throat structure, fractal dimension and reservoir physical property are discussed, the contribution of pore throat structure to permeability is analyzed, and a permeability prediction model is established. The samples of Shaximiao Formation can be divided into four types: type Ⅰ samples have low displacement pressure, favorable physical properties and good pore connectivity; the average fractal dimension is 2.11, the pores are mainly macropores and mesopores with radius >0.1 μm, and the pore throat with radius >1 μm contributes more than 90% of the permeability. As for type Ⅱ samples, the displacement pressure are 0.4-1.0 MPa, the average porosity and permeability are 9.72% and 0.375×10^-3 μm², respectively, and the fractal dimension is 2.20; the mesopore content increases and mesopores contribute most of the permeability. The displacement pressure and fractal dimension of type Ⅲ and Ⅳ samples are significantly higher than those of type Ⅰ and Ⅱ samples, and the low porosity and lack of macropore lead to low permeability. The macropores and mesopores with radius > 0.1 μm contribute more than 98% of the permeability of Shaximiao Formation. Fractal dimension is a good indicator of pore throat structure. Fractal dimension is significantly negatively correlated with pore throat radius, maximum mercury saturation and permeability, and is positively correlated with displacement pressure and relative separation coefficient of pore throat. There is a strong correlation between fractal dimension and pore throat composition, and a permeability quantitative prediction model based on fractal dimension, porosity and maximum pore throat radius is established.

2024, 46(1): 215-215.

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2024 Vol. 46, No. 1

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