Oil & Gas Geology-2023, Volume 44 Issue 5

Complex gas-water contacts in tight sandstone gas reservoirs： Distribution pattern and dominant factors controlling their formation and distribution

Jianhui ZENG, Yaxiong ZHANG, Zaizhen ZHANG, Juncheng QIAO, Maoyun WANG, Dongxia CHEN, Jingli YAO, Jingchen DING, Liang XIONG, Yazhou LIU, Weibo ZHAO, Kebo REN

2023, 44(5): 1067-1083. doi:10.11743/ogg20230501

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In recent years， extensive exploration and exploitation activities in tight sandstone gas reservoirs have highlighted the common phenomenon of water production， indicating complex gas-water contacts. Exploring gas layers while avoiding water layers has become critical to the efficient exploration and exploitation of tight sandstone gas reservoirs. This study presents comprehensive geological analyses of gas-water contacts in simple gentle tectonic zones （tight sandstone gas reservoirs in the Sulige and Daniudi areas in the Ordos Basin）， a transition zone of simple gentle to complex uplift （Hangjin Banner in the Ordos Basin）， and complex uplift zones （tight-gas reservoirs in the western Sichuan Basin）. Combined with the core-scale and pore-scale physical simulations of gas-water contact in tight sandstone， we clarify the types and characteristics of gas-water contacts in tight-gas sandstone reservoirs， reveal the dominant factors controlling the formation and distribution of intricate gas-water contacts based on the sand bodies， cores， and pores， and establish corresponding gas-water distribution patterns. Key findings are as follows. In terms of sand body， there are primarily six types of gas-water contacts within， including （1） the simple type of gas layer without water layer；（2） the normal type with gas layer underlain by water layer；（3） the inverted type with gas layer overlaid by water layer；（4） the hybrid type with gas and water in the same layer；（5） the isolated type with water layer within a gas layer； and （6） the simple type of water layer without gas. The distribution range， style， and boundary of gas-water contacts are governed by hydrocarbon-generating intensity， reservoir heterogeneity， and a combination of source rock-reservoir pressure differences and tectonic activity， respectively. At core-scale， permeability coupled with charging dynamics of the tight sandstone governs the critical conditions for the formation and distribution of gas-water contacts. At pore-scale， the coupling of pore throat size and coordination number with charging pressure dictates the fluid occurrence and seepage characteristics， determining the critical conditions for the formation and distribution of gas-water contacts. Owing to the collective effects of dominant factors from sand body， core-scale， and pore scale and their differences， tight-gas reservoirs with different source rock-reservoir assemblages exhibit different gas-water distribution patterns.

Classification， origins， and evolution of macerals in the Precambrian-Eopaleozoic sedimentary rocks

Qingyong LUO, Ningning ZHONG, Meijun LI, Jin WU, Imran Khan, Ye ZHANG, Qing CHEN, Xiangzhong YE, Wenhao LI, Wenming JI, Anji LIU, Jingyue HAO, Lipeng YAO, Jia WU

2023, 44(5): 1084-1101. doi:10.11743/ogg20230502

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This study delves into the intricate organic macerals found in ancient Precambrian-Eopaleozoic sedimentary rocks， despite their simple biotic sources. Based on the observation and analysis of a vast array of naturally- and artificially-matured rock samples from domestic and international locations， we classify the macerals according to four dominant factors， namely biogenesis， origin， sedimentary transformation， and thermal maturation. The key classe determined include vitrinite-like macerals， sapropelinites， solid bitumen， zooclasts， and inertinites. The macerals in low-maturity marine source rocks are chiefly composed of lamalginite， bituminite， and mineral-bituminous matrix. In contrast， high- to over-mature marine source rocks predominantly contain in-source solid bitumens. Notably， graptolite periderms， as significant components of organic matter， are prevalent in the shales of the Wufeng-Longmaxi formations. We provide deeper insights into the origins of the most typical macerals prone to be overlooked previously， including vitrinite-like maceral particles and in-source solid bitumens. The vitrinite-like maceral particles in the Precambrian rock samples may arise from the microbial degradation of lower aquatic organisms during early diagenesis. In-source solid bitumens form either as solid residues arising from the cracking of soluble organic matter that remained within source rocks after primary migration or as solid-phase products during the thermal evolution of the residual kerogen of sapropelinites after absorbing and assimilating soluble organic matter. Lastly， as indicated by integrated research on the naturally- and artificially-matured rock samples， the preexisting organic matter in high to over mature Precambrian， Cambrian， and Ordovician-Silurian graptolite-bearing shales in China resemble the present-day organic matter in the Mesoproterozoic Xiamaling Formation， Cambrian Alum Shale Formation， and Ordovician graptolite-bearing Alum Shale Formation， respectively. The reflectance of graptolite periderms， vitrinite-like maceral particles， and in-source solid bitumens can be utilized to characterize the thermal maturity of organic matter in the Precambrian-Eopaleozoic marine source rocks.

Classification and origin of micropores in carbonates and their effects on physical properties of rocks

Haizhou QU, Xinyu GUO, Wei XU, Wenhao LI, Song TANG, Yani DENG, Shipeng HE, Yunfeng ZHANG, Xingyu ZHANG

2023, 44(5): 1102-1117. doi:10.11743/ogg20230503

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Micropores in carbonate rocks are micron- to nano-sized pores with pore sizes less than 50 μm. Various single-factor and comprehensive classification methods for these micropores are available， with Kaczmarek’s comprehensive scheme being widely applied due to its integration of aphanocrystalline morphologies and physical properties. While the fluid intrusion method， image analysis， and mathematical statistics serve as primary characterization methods for micropores， a combination of qualitative and quantitative methods can achieve their comprehensive characterization. Micropores are primarily found between aphanocrystallines or very fine crystallines， primarily growing on primary minerals. Diagenetic processes， especially mineral transformations， dolomitization， and recrystallization， significantly influence micropore formation. Additionally， the morphologies and configurations of aphanocrystallines govern the spatial geometry of micropores， further influencing the physical properties of rocks. As the understanding of micropores in carbonates deepens， it is necessary to refine existing theories about micropore classification and origin by combining the context of China. Furthermore， there is a need to establish and refine the evaluation criteria for rocks of microporous carbonate reservoirs using more advanced characterization techniques such as in-situ microanalytical methods， confocal laser scanning microscopy （CLSM）， and digital core modeling. This will be of theoretical and technical support to research on the micro characteristics of deep carbonate reservoirs prevalent in China.

Exploration discoveries and implications of well Zheng 10 in the Zhengshacun area of the Junggar Basin

Huimin LIU, Guanlong ZHANG, Jie FAN, Zhiping ZENG, Ruichao GUO, Yajun GONG

2023, 44(5): 1118-1128. doi:10.11743/ogg20230504

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The expansion toward deep-to-ultra-deep oil and gas exploration is strategically vital for reserve growth and production addition in the Junggar Basin. Well Zheng 10 drilled in the Zhengshacun area in the hinterland of the Junggar Basin underscores the significant potential of the basin’s central part for ultra-deep oil and gas exploration. This study first presents the characteristics of hydrocarbon reservoirs in the area， emphasizing the elements of pertroleum system， such as source rocks， reservoirs， and migration pathways， that contribute to hydrocarbon accumulation. Accordingly， it identifies the determinants of hydrocarbon accumulation in the area and establishes the hydrocarbon accumulation mode. Furthermore， this study presents the implications of these factors for deep-to-ultra-deep oil and gas exploration in the area. The results reveal three major factors influencing the hydrocarbon accumulation therein：（1） A mechanism driven by low geothermal gradients and overpressure for hydrocarbon-generating evolution. This mechanism extends the oil window and elevates the transformation ratio， thereby significantly enriching hydrocarbon resources；（2） A four element （including low geothermal gradient， overpressure， chlorite coating， and zeolite dissolution） -controlled reservoir formation. This pattern redefines the lower depth limit for the development of conventional clastic reservoirs， thus broadening the scope for hydrocarbon exploration. （3） A migration mechanism governed by both faults and overpressure. This mechanism provides high-energy pathways for hydrocarbon migration and determines the vertical differential hydrocarbon migration， thus ensuring efficient hydrocarbon charging in ultra-deep reservoirs. By integrating superimposed factors including ultra-deep source rock evolution， pressure changes， tectonic shifts， diagenetic sequences， and hydrocarbon accumulation periods， we establish a hydrocarbon accumulation mode for the study area. This mode incorporates the temperature-pressure control over hydrocarbon-generating evolution， four element-controlled reservoir formation， and hydrocarbon migration governed by both faults and overpressure. This study aims to provide theoretical guidance and a scientific basis for new exploratory well emplacement and the delineation of potential new play fairways in the area.

Characteristics and quality determinants of Carboniferous volcanic reservoirs in the Hongche Fault Zone， Junggar Basin

Yao ZHAO, Hong PAN, Feifei LUO, Liang LI, Danyang LI, Zongrui XIE, Donglian LU, Qin ZHANG

2023, 44(5): 1129-1140. doi:10.11743/ogg20230505

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The Carboniferous volcanic rocks within the Hongche Fault Zone in the Junggar Basin serve as pivotal exploration and exploitation targets. However， ambiguities regarding the characteristics and quality determinants of the volcanic reservoirs pose challenges for the forthcoming emplacement of exploratory and exploitation wells. Leveraging the data from core， ordinary thin section， and casting thin section observation， as well as image logs， we conduct a fine-scale lithological classification for these reservoirs. Furthermore， we identify the types of reservoir spaces and reveal the factors influencing the reservoir quality. This study seeks to provide a scientific basis for selecting the optimal exploration and exploitation targets. The results are as follows：（1） The volcanic reservoirs predominantly consist of volcanic breccia， tuffaceous volcanic breccia， tuff， basalt， and andesite. Their storage spaces are dominated by secondary pores and micro-fractures. These reservoirs are characterized by ultra-low porosity （average： 9.69 %） and ultra-low permeability （average： 0.24 × 10^-3 μm²）. Notably， the Carboniferous volcanic breccia exhibits the most favorable physical properties， followed by andesite and basalt；（2） The physical properties of these reservoirs are collectively molded by volcanic rocks’ lithologies and lithofacies， diagenism， and tectonism. Specifically， the lithologies determine the types of primary pores and their development degree. In comparison， the lithofacies are instrumental in governing the types and distributions of lithologies， determining the material composition of volcanic rocks and fundamentally influencing the compaction and subsequent dissolution of volcanic rocks. Therefore， the lithofacies serve as the predominant factor influencing the reservoir quality. Several processes， including weathering， leaching， dissolution， and fault activity， contribute to the formation of a fracture-dissolution pore system， significantly enhancing the reservoir quality. In contrast， compaction and the filling process greatly reduce the number of primary pores， leading to poor physical properties of reservoirs.

Development model and significance of favorable lithofacies association of sandy braided river facies of the Cretaceous Bashijiqike Formation in Zhongqiu 1 well block， Kuqa Depression， Tarim Basin

Zhiyong GAO, Yongping WU, Zhaolong LIU, Cong WEI, Yongzhong ZHANG, Cuili WANG, Qunming LIU

2023, 44(5): 1141-1158. doi:10.11743/ogg20230506

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The deep Cretaceous Bashijiqike Formation in well Zhongqiu 1 in the Kuqa Depression tested high flow rate of natural gas. However， due to the small number of wells， large burial depth， and strong reservoir heterogeneity， it is difficult to evaluate the favorable reservoirs in the area and analyze the control factors of differential well productivity. Based on the isochronous characteristics of flood surface， we establish an isochronous stratigraphic framework of Bashijiqike Formation through the analysis of core sedimentary facies and identification of facies markers. The evolution process of progradation （lake level descending） of braided river delta front， plain， and alluvial plain braided river is established from bottom to top in the three internal sedimentary units. In Zhongqiu 1 well block， the reservoir intervals showing productivity difference occur in the upper Ba 2 Member and Ba 1 Member which are mainly deposited in the sandy braided rivers on alluvial plain above the maximum flooding surface， and the main river channel has been in different positions in different periods during their deposition. Taking into account factors such as sedimentary microfacies， coarse and fine structure of detrital particles， pore types and characteristics， porosity and permeability data， and fracture intensity， the sandy braided river sedimentary bodies of the Bashijiqike Formation can be divided into nine types in terms of lithofacies combination， with the differences in sedimentary microfacies serving as the basis， and types I—V being favorable lithofacies combinations. A favorable lithofacies combination development model is built for the sandy braided river facies of the Bashijiqike Formation in the Zhongqiu 1 well block. The proportion of favorable lithofacies combinations in this area featuring high in the east and low in the west， serves to determine the differences in gas bearing properties. It is predicted that the SN-trending area between the eastern line across wells Zhongqiu 101， Zhongqiu 1， and Zhongqiu 104 and the western line across wells Zhongqiu 102 and Zhongqiu 2， is favorable for the development of large-scale effective reservoir， especially on the north and northeast sides.

Phase evolution and accumulation mode of hydrocarbons in deep coarse-grained clastic reservoirs in the Yanjia area， Dongying Sag， Bohai Bay Basin

Yongshi WANG, Jianqiang GONG, Dongxia CHEN, Yibo QIU, Shuwei MAO, Wenzhi LEI, Huaiyu YANG, Qiaochu WANG

2023, 44(5): 1159-1172. doi:10.11743/ogg20230507

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Deep hydrocarbon reservoirs in the Yanjia area in the northern steep slope zone of the Dongying Sag experienced complex thermal evolution. The resultant multiple hydrocarbon phases pose challenges for the exploration and exploitation of deep hydrocarbons. Using basin modeling， pressure-volume-temperature （pVT） phase simulation， and the analysis of hydrocarbon fluid inclusions， we reveal the evolutionary process of deep hydrocarbon phases in the Yanjia area and establish the hydrocarbon accumulation modes of different types of reservoirs. Findings indicate that deep hydrocarbons in the 4^th member of the Shahejie Formation in the Yanjia area exhibit an orderly phase distribution in the vertical direction， with reservoirs of light oil， condensate gas， and dry gas found from shallow to deep. While thermal evolution predominantly governed the formation of hydrocarbon phases in deep coarse-grained clastic rocks， the phase evolution in condensate gas reservoirs stemmed from hydrocarbon generation from kerogen， crude oil cracking， and external natural gas charging. By integrating insights into the hydrocarbon phases， characteristics， and temperature and pressure evolutionary histories of different hydrocarbon reservoirs， we propose a hydrocarbon accumulation mode for deep coarse-grained clastic rocks in the Yanjia area. This mode encompasses multi-stage hydrocarbon generation， migration via superimposed sand beds within middle fans while sealed by mudstone within root fans， and the orderly phase distribution of hydrocarbons. This study seeks to provide theoretical guidance for the efficient exploration of deep hydrocarbons in continental downfaulted basins.

Influence of sand-mud assemblages in tight sandstones on reservoir storage spaces： A case study of the lower submember of the 3^rd member of the Paleogene Shahejie Formation in the Linnan sub-sag， Bohai Bay Basin

Junliang LI, Xin WANG, Weiqing WANG, Bo LI, Jianhui ZENG, Kunkun JIA, Juncheng QIAO, Kangting WANG

2023, 44(5): 1173-1187. doi:10.11743/ogg20230508

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The swift shifts in sedimentary water bodies in continental petroliferous sedimentary basins result in frequent intercalation of sandstone and mudstone layers. Various sandstone-mudstone intercalation patterns （sand-mud assemblages） lead to significant differences in the storage spaces in sandstone reservoirs. Focusing on the lower submember of the 3^rd member of the Paleogene Shahejie Formation in the Linnan sub-sag， Huimin Sag， Bohai Bay Basin， we first analyze the spatial assemblages and single-layer thickness of sandstone and mudstone layers. Using casting thin section observations， physical property tests， and micro-CT scanning， we systematically elucidate the physical properties， pore types， and pore structures of sandstone reservoirs with different sand-mud assemblages. As indicated by the findings， the lower submember contains nine types of sand-mud assemblages， namely thick mudstone interbedded with thin sandstone， medium mudstone interbedded with thin sandstone， thick mudstone interbedded with medium sandstone， intercalated thin sandstone and thin mudstone， intercalated medium sandstone and medium mudstone， intercalated thick sandstone and thick mudstone， medium sandstone interbedded with thin mudstone， thick sandstone interbedded with medium mudstone， and thick sandstone interbedded with thin mudstone. The ionic interactions between sandstones and mudstones lead to strong heterogeneity in the storage capacity of sandstone reservoirs with different sand-mud assemblages. For sand-mud assemblages with low net-to-gross ratios， mudstones supply ample CO₃^2-， Ca²⁺， Fe²⁺， and Mg²⁺ to sandstones， and sandstones are completely filled with cements. Consequently， the sandstone reservoirs become extremely tight. However， when this ratio rises， mudstones cannot provide sandstones with sufficient ions mentioned above. In this case， sandstones near the sand-mud interfaces exhibit strong carbonate cementation， forming extremely tight reservoirs. In contrast， the interior of the sandstones shows weak carbonate cementation， with a small number of primary pores present. Additionally， the sand-mud assemblages with relatively thick sandstones promote organic acid infiltration， enhancing reservoir quality through the formation of numerous intergranular dissolution pores. Based on the differences in sand-mud assemblages， we reveal the influence of sand-mud assemblages on the evolutionary path and model of the storage spaces in sandstone reservoirs. Our insights are pivotal for predicting sweet spots in tight sandstone reservoirs.

Multistage structural superimposition and its control on buried hills in the Lyuda uplift zone， Bohai Bay Basin

Shujuan ZHAO, Sanzhong LI, Chengmin NIU, Jiangtao ZHANG, Zhen ZHANG, Liming DAI, Yu YANG, Jinyue LI

2023, 44(5): 1188-1202. doi:10.11743/ogg20230509

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The Lyuda uplift zone， situated in the northwestern Bohai Sea area， Bohai Bay Basin， experienced multiphase tectonic events in superimposition during the Mesozoic-Cenozoic， leading to the formation of various interior faults with intricate deformations. However， the Paleozoic and Mesozoic structures within this zone remain understudied. Based on a detailed structural analysis with 3D seismic data， this study presents the following findings. （1） The Lyuda uplift zone predominantly experienced top-to-north thrusting during the Indosinian， forming NW- to nearly EW-trending open folds and thrust-nappe faults；（2） The uplift zone primarily underwent localized extension and deposition under compression during the Early and Middle Yanshanian， with the absence of significant angular unconformity between the Middle-Lower Jurassic and the Upper Jurassic-Lower Cretaceous strata；（3） The uplift zone principally experienced top-to-northwest thrusting during the Late Yanshanian；（4） The uplift zone witnessed the emergence of domino-style extensional-detached faults and the deposition in half grabens due to NW-SE directed extension during the Early Himalayan. Among these structures， the Indosinian NW- to nearly EW-trending thrust faults shape the basement tectonic framework for the Lyuda uplift zone， while the Late Yanshanian and Early Himalayan movements either inherited or modified the earlier fault system. The Late Cretaceous marked a pivotal transition for the Lyuda uplift zone’s tectonic framework from trending NW to nearly EW to NE. The Qinhuangdao 30-1 and Lyuda 25-1 structural buried hills， located in the tectonic transition zone， emerged from the superimposition of the Indosinian nearly S-N directed compression， the Late Yanshanian NW-SE directed compression， and the Early Himalayan NW-SE directed extension. In contrast， 428 structural buried hill in the south is controlled by the nearly E-W-trending thrust during the Indosinian and the extensional fault system during the Yanshanian and Early Himalayan.

Factors controlling the development of deep and ultra-deep coarse-grained siliciclastic reservoirs with high quality in the steep slope zone of the Minfeng sub-sag， Dongying Sag， Bohai Bay Basin

Jiageng LIU, Yanzhong WANG, Yingchang CAO, Shuping WANG, Xuezhe LI, Zhukun WANG

2023, 44(5): 1203-1217. doi:10.11743/ogg20230510

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Deep and ultra-deep layers within petroliferous basins have emerged as new targets in global oil and gas exploration. However， the major factors influencing the development of high-quality reservoirs within these layers remain poorly understood， posing challenges for effective exploration. This study focuses on the coarse-grained siliciclastic reservoirs in the nearshore subaqueous fan in the lower submember of the 4^th member of the Shahejie Formation in the steep slope zone of the Minfeng sub-sag， Dongying Sag. By combining methodologies including casting thin section observation， scanning electron microscopy （SEM）， cathodoluminescence microscopy-based identification of minerals in thin sections， fluid inclusion thermometry， and paleopressure reconstruction， as well as the analytical results of the burial and thermal history， we comprehensively examine the reservoirs’essential characteristics， hydrocarbon charging history， pressure evolution， and factors controlling the development of high-quality reservoirs. The findings include：（1） The coarse-grained siliciclastic reservoirs in the study area are predominantly lithic arkoses and feldspathic litharenites. They exhibit medium to strong compaction and are dominated by ferrodolomite cementation， followed by quartz overgrowth. They show overall weak dissolution dominated by feldspar dissolution. The reservoir spaces comprise mostly primary pores， along with some others developed from feldspar dissolution. （2） Two oil charging stages and one natural gas charging stage were identified： an early mature-oil charging between 37.2～25.8 Ma and a later highly-mature-oil charging from 12 Ma onwards. The natural gas charging has lasted till now since 3.6 Ma. （3） The reservoirs have experienced two distinct pore pressure-increasing cycles： 45～24.6 Ma and from 24.6 Ma to present， corresponding to the two hydrocarbon charging stages. （4） Favorable lithofacies lay the foundation for the development of high-quality reservoirs dominated by primary pores in the study area. The inhibitive effects of overpressure hydrocarbon charging on compaction and cementation are crucial to the development of high-quality reservoirs. The weak dissolution of feldspar and carbonate minerals in the deep closed system leads to a low increment in porosity. However， the reduction rate of the reservoir porosity with depth declines significantly at burial depths beyond 3 750 m， and the development of deep high-quality reservoirs dominated by primary pores expands the lower limit of depth for exploration.

Organic petrology of shales in the Mesoproterozoic Xiamaling Formation in the northern part of North China

Jin WU, Qingyong LUO, Ningning ZHONG, Zilong FANG, Jincai DUAN, Wuji ZHANG, Yaxin CUI

2023, 44(5): 1218-1230. doi:10.11743/ogg20230511

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The shales of the Mesoproterozoic Xiamaling Formation in the northern part of North China， which rank among China’s most ancient marine source rocks， are characterized by simple biotic sources， high organic matter abundance， and low maturity. However， there is a lack of detailed study on the morphologies and origins of macerals in these shales. This study delves into the composition， characteristics， and origins of macerals in these shales using organic petrological methods. The results highlight a complex maceral composition in the Xiamaling Formation shales， encompassing bituminite， lamalginite， vitrinite-like maceral particles， mineral-bituminous groundmass， and thucholite. Notably， microscopic examinations illuminate transitional shifts in the optical properties of vitrinite-like maceral particles， bituminite， and lamalginite. These shifts—a gradually decreasing random reflectance and progressively increasing fluorescence—are intimately linked to the origins of these macerals. As lamalginite undergoes gradually enhanced anaerobic microbial degradation， it evolves into bituminite and vitrinite-like maceral particles. Additionally， the organic matter forms thucholites after experiencing ionizing radiation-induced polymerization of radioactive mineral particles， which primarily comprise monazite and thorite. The thermal radiation of these particles appears to have a certain influence on organic matter maturity only in a limited range.

Orbital forced high-resolution sequence boundary identification of marine-continental transitional shale and its geological significance： A case in Shan 2³ sub-member at the eastern margin of Ordos Basin

Yueli LIANG, Xiaoming ZHAO, Xi ZHANG, Shuxin LI, Jiawang GE, Zhihong NIE, Tingshan ZHANG, Haihua ZHU

2023, 44(5): 1231-1242. doi:10.11743/ogg20230512

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The marine-continental transitional shale is of good exploration prospect， but it is difficult to construct a high-resolution sequence stratigraphic framework due to its multiple pay zones， and thin single-layer thickness with rapid lithofacies change. The theory of cyclostratigraphy provides an effective means for the division and correlation of high-frequency cycles. The study determines the high-resolution sequence boundary of marine-continental transitional shale in the 2³ sub-member of Shanxi Formation （Shan 2³ sub-member） at the eastern margin of Ordos Basin， based on core analysis and logging data， combined with the high-resolution sequence stratigraphy and cyclostratigraphy. The GR， Th/U and TOC sequences of the Shan 2³ sub-member are applied to obtain the astronomical parameters recorded in the sediments by filtering. A comprehensive analysis of the sub-member in terms of lithology， logging and geochemical elements serves to identify fourth-order sequence boundaries. The 405 kyr long eccentricity cycle has a good coupling relationship with the fourth-order sequences， and the sub-member can be divided into four fourth-order sequences （PSQ1—4）. According to the relationship between the short eccentricity and the fifth-order sequence， the sub-member can be sub-divided into 12 fifth-order sequences （FSQ1—12）. On this basis， we analyze the coupling relationship of orbital cycle with high-resolution sequence， sea level fluctuation， sedimentary environment evolution and lithofacies association. The long eccentricity cycle controls the evolution of sedimentary environment （facies） by adjusting 0.4 Myr scale sea level change， and affects the development of dominant shale reservoirs； while the short eccentricity cycle controls the evolution of sedimentary environment （sub-facies） by adjusting the sea level change of 0.1 Myr scale， and affects the development of shale reservoir sweet spots. In all， the high-resolution sequence division and correlation technology of shale strata as proposed in cyclostratigraphy， can be of theoretical reference and technical support to precisely identifying dominant shale and geo-steering design of horizontal wells.

Bauxite series in the Upper Paleozoic weathering crusts in the southwestern Ordos Basin： Development and distribution of dominant reservoirs

Han LI, Jinhua FU, Hancheng JI, Lei ZHANG, Yuwei SHE, Wei GUAN, Xianghui JING, Hongwei WANG, qian CAO, Gang LIU, Jiayi WEI

2023, 44(5): 1243-1255. doi:10.11743/ogg20230513

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In the Longdong area—a gas exploration area in the southwestern Ordos Basin， breakthroughs have been made in gas exploration in the bauxite series of the Upper Paleozoic Permian Taiyuan Formation， offering a new exploration target. However， the distribution of the bauxite series and reservoir developmental characteristics within remain unclear， hindering exploration progress. Using data from core and thin-section observations， logs， and seismic data， we analyze the provenance， sedimentary environment， and formation process of the bauxite series and explore the characteristics and formation mechanisms of reservoirs within the bauxite series. Based on these effects， we establish the formation and distribution patterns of the bauxite series， as well as reservoir development model. The results are as follows. （1） The bauxite series in the Longdong area primarily originate from carbonate rocks in the Lower Paleozoic Majiagou Formation. （2） The bauxite series is developed in a warm and rainy sedimentary environment under marine regression. In the vertical direction， the rock series consists of funnel-shaped， lenticular， and stratoid lithologic assemblages. The lithologic assemblages of different origins are controlled by factors such as volumetric space of karsts and leaching degree. Regarding the planar distribution， the bauxite series is dictated by paleogeomorphology. For instance， karst-related sinkholes in the highlands house funnel-shaped bauxite series with considerable vertical thickness； karst-related terraces in the slope zone predominantly contain lenticular bauxite series with a broad and continuous lateral distribution， and the depression zones show the development of stratoid bauxite series. （3） The karst-related negative landforms serve as a key factor controlling the development of bauxite series， while drainage channels are critical to the development of dominant reservoirs. Furthermore， as micro-paleogeomorphic units， including sinkholes in the highlands and terraces in the slope zone， provide favorable conditions for the development of dominant reservoirs within the bauxite series. These findings provide a basis for seeking high-quality reservoirs within the bauxite series in the Ordos Basin and can be used as a reference for exploring new types of natural gas.

The mechanism of “convergence ahead of accumulation” and its geological significance for gas reservoirs in Paleogene Huagang Formation across the central inverted structural zone of Xihu Depression， East China Sea Shelf Basin

Yingzhao ZHANG, Wei ZOU, Zhongyun CHEN, Yiming JIANG, Hui DIAO

2023, 44(5): 1256-1269. doi:10.11743/ogg20230514

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Inverted structural zones in many onshore basins around the world are frequently found to be home to oil and gas traps and have been the targets for studies for years. However， offshore inverted structural zones， in the contrary， are seldom explored because of less drilling due to high cost. Taking the central inverted structural zone of Xihu Depression as an example， this paper focuses on the original capacity of hydrocarbon convergence in the source rock series and the dynamic accumulation of hydrocarbons from source to reservoir， with the aim of revealing the hydrocarbon enrichment law. The correlation of structural evolution， hydrocarbon generation and reservoir evolution as well as hydrocarbon charging history reveals that the massive hydrocarbon generation and charging of source rocks preceded the formation of traps in the northern part of the zone. The early-generated gas formed “semi accumulation” with high abundance within the series， i.e.， “convergence first”； and then migrated upwards and accumulated in traps formed later during tectonic movements， i.e.， “later accumulation”. The reservoirs show a trend of increasing natural gas maturity from deep to shallow. Based on these results， the paper proposes the new model of “convergence ahead of accumulation”， which not only reasonably explains the mismatch of timing among the hydrocarbon generation， trap formation and hydrocarbon charging in the Huagang Formation in the series， but also reveals the control effect of ancient tectonic background on the current accumulation of oil and gas. Under the guidance of this model， the key factors for the formation of large-scale natural gas reservoirs in the zone are revealed， and the B structure in the zone is pinpointed to be a perfect place for “convergence ahead of accumulation”. The new model can be applied to other offshore petroliferous basins with similar geological conditions.

Natural gas sources and migration pathways of the Baodao 21-1 gas field in the deep-water area of the Qiongdongnan Basin

Li YOU, Yongbin QUAN, Lei TUO, Changyu TENG, Gaokun ZUO

2023, 44(5): 1270-1278. doi:10.11743/ogg20230515

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The discovery of Baodao 21-1 gas field highlights a landmark achievement in the hydrocarbon exploration efforts in the Baodao Sag of the Qiongdongnan Basin over the past three decades， opening up new exploration prospects. To further explore the gas potential in the sag， understanding the sources and migration pathways of natural gas is paramount. This study delves into the exploration of the Baodao 21-1 gas field， offering detailed insights into the composition and carbon isotopes of natural gas， as well as condensate biomarkers， based on petroleum geochemistry and fault system characterization. Furthermore， this study presents a fine-scale characterization of the geometrical morphologies and kinematic properties of dominant faults and evaluates their role in natural gas enrichment. Key findings include. （1） The Baodao 21-1 gas field showcases high concentrations of heavy hydrocarbon gases， low drying coefficients， and light carbon isotopes， distinguishing itself from Y13 and L17 gas fields. This suggests significant contributions from marine algae-derived sapropelic organic matter besides terrigenous organic matter. （2） The Baodao 21-1 structure experienced three stages of hydrocarbon charging. The structure’s faults and the deltaic sand bodies in the third member of the Lingshui Formation serve as effective pathways for hydrocarbon migration. The fault morphology and differential activity dictate the hydrocarbon accumulation and migration. All these make the Baodao 21-1 gas field become a major area for hydrocarbon accumulation. （3） The natural gas enrichment mode for the gas field is established. This mode includes proximity to major hydrocarbon-generating sags， gas accumulation along a large-scale structural ridge and a fault-plane ridge， and efficient migration pathways via long-term active faults in large scale connecting source rocks， and deltaic sandstones. This study lays the groundwork for forthcoming exploration in both the Baodao Sag and even the Qiongdongnan Basin as a whole.

Exploring the dynamic hydrocarbon accumulation process of the Enping 17 sub-sag in the Enping Sag， Pearl River Mouth Basin

Yuling SHI, Zulie LONG, Xiangtao ZHANG, Huahua WEN, Xiaonan MA

2023, 44(5): 1279-1289. doi:10.11743/ogg20230516

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In this study， we determine the hydrocarbon sources and distribution in the Enping 17 sub-sag， Pearl River Mouth Basin （PRMB） through geochemical analyses. Using the selected optimal fault attributes， we quantitatively evaluate the hydrocarbon transport capacity of faults during different geologic periods. Furthermore， we reproduce the paleotectonic morphologies of primary seismic reflectors in the Enping 17 sub-sag since 23.03 Ma with the aid of the MOVE software， revealing the influence of the paleotectonic morphological changes of seismic reflector T $70$ on hydrocarbon redistribution in the vertical direction and among various tectonic zones. Finally， we reconstruct the dynamic hydrocarbon accumulation process and predict potential hydrocarbon exploration targets. The results are as follows. （1） The crude oil of the Enping 17 sub-sag originates primarily from source rocks in the 3^rd， 4^th， and 5^th members of the Eocene Wenchang Formation. Faults with throws ranging from 100—130 m can transport hydrocarbons to the Enping Formation， while those with throws exceeding 130 m may create conducive conditions for hydrocarbons to migrate vertically toward the medium and shallow reservoirs through the Enping Formation. （2） The hydrocarbons in the sub-sag underwent three migration and accumulation stages： the migration and accumulation near sources in the early stage， the southward migration and accumulation in the middle stage， and the S-N two-way migration and accumulation in the late stage. Due to the weak vertical hydrocarbon transport capacity of faults in the late stage， the Enping Formation served as a hub for hydrocarbon redistribution in the vertical direction and among various tectonic zones. Prior to 10.00 Ma， hydrocarbon migration and accumulation primarily occurred near sources under the paleostructural surface on seismic reflector T $70$ . From 10.00 Ma to 5.33 Ma， hydrocarbons migrated to and accumulated in the southern tectonic zones along the carrier beds of the Enping Formation. After 5.33 Ma， hydrocarbon migration was diverted northward under the paleostructural surface on T $70$ ， signaling the general commencement of S-N two-way migration and accumulation. In conclusion， the favorable exploration targets in the Enping 17 sub-sag include the Paleogene structural traps along NW-trending structural ridges， as well as the tectono-lithologic or stratigraphic-lithologic traps in the Enping Formation at the edge of the northern paleo-uplift.

Intelligent prediction of inter-well connectivity path in deep fractured-vuggy reservoirs

Zhijiang KANG, Dongmei ZHANG, Zhenkun ZHANG, Ruiqi WANG, Wenbing JIANG, Kunyan LIU

2023, 44(5): 1290-1299. doi:10.11743/ogg20230517

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Deep fractured-vuggy carbonate reservoirs， usually a result of multi-stage tectonic movements and paleo-karst modification， are complex in structure and strong in heterogeneity. Conventional connectivity identification methods， primarily based on clastic rock reservoirs， are not suitable for carbonate reservoirs. This research aims to realize an automatic evaluation of inter-well connectivity by studying static and dynamic data and incorporating techniques such as multifractal and curve similarity analyses into the evaluation. These techniques can be employed to extract characteristic dynamic parameters and detect response level of neighboring wells under different mechanisms. Deep residual networks are used to integrate multi-attribute seismic data for characterizing the spatial structure of reservoirs. Additionally， reinforcement learning and multi-objective algorithms are also employed to automatically search for three-dimensional connectivity paths. Extracted dynamic response features and the distribution patterns of three-dimensional connectivity paths in typical fracture-cavity units in the Tahe oilfield with different karst backgrounds demonstrate that the fracture network serves as the primary communication channel among wells in weathered crust karst， exhibiting good multi-directional connectivity. The main and secondary faults are the primary channels connecting between wells within fault-controlled karst oil reservoirs， forming a strip-like connectivity pattern along the faults. The connectivity of paleo-underground river karst along multiple layers of underground river networks with local filling and collapse exhibiting segmental characteristics. The research results are of guiding significance for exploring remaining oil and enhancing recovery of deep fractured-vuggy reservoirs.

A method for predicting fault-induced changes of hydrocarbon migration pathways along sand carrier beds and its application

Chunbo HE, Yaxiong ZHANG, Yinghua YU, Hongqi YUAN

2023, 44(5): 1300-1307. doi:10.11743/ogg20230518

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To reveal the distribution patterns of shallow hydrocarbons in slope zones of petroliferous basins， we explore the role of faults in changing the pathways for hydrocarbon migration along sand carrier beds， as well as the exact change. By matching the hydrocarbon leakage location of the cap rock with the dominant migration pathway along faults and sand carrier beds， we establish a method for predicting the fault-induced changes of hydrocarbon migration pathways along the sand carrier beds. By applying this method to the Qikou Sag in the Bohai Bay Basin， we predict the Zhaobei fault-induced change of pathways for hydrocarbon migration along the sand carrier beds in the lower submember of the 1^st member of the Shahejie Formation where hydrocarbons migrate into the shallow Guantao Formation. The results indicate only one change in the migration pathways induced by the Zhaobei fault， lying in the middle of the lower submember of the 1^st member of the Shahejie Formation. In this part， hydrocarbons migrating via the sand carrier beds in the lower submember migrate upward along the Zhaobei fault and accumulate in the overlying shallow Guantao Formation. This prediction result aligns with the fact that hydrocarbons found in the shallow Guantao Formation near the Zhaobei fault are predominantly distributed in the middle of the lower submember. Therefore， the method proposed in this study is feasible in predicting fault-induced changes of the hydrocarbon migration pathways along the sand carrier beds.

Evolutionary process of the wettability of low-permeability sandstone reservoirs under the control of diagenesis and its mechanism： A case study of the Dongying Sag， Bohai Bay Basin

Xin WANG, Jianhui ZENG, Kunkun JIA, Weiqing WANG, Bo LI, Cong AN, Wen ZHAO

2023, 44(5): 1308-1320. doi:10.11743/ogg20230519

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Wettability plays a critical role in dictating the fluid percolation within low-permeability sandstone reservoirs. However， the wettability evolutionary mechanisms remain ambiguous given the frequent changes in the fluid properties and mineral types and compositions in these reservoirs throughout diagenesis. This opacity severely hampers the research on the mechanisms of hydrocarbon accumulation in the reservoirs. This study centers on the upper submember of the 4^th member of the Paleogene Shahejie Formation in the Dongying Sag， Bohai Bay Basin. Based on the analysis of geological data， we undertake a systematical analysis of diagenesis’s controlling effects on the wettability of low-permeability sandstone reservoirs through observation of casting thin sections and the X-ray diffraction analysis of mineral compositions， Amott wettability tests using nuclear magnetic resonance （NMR） equipment， and experiments of contact angles in a solid-oil-water system， both under high temperature and pressure. The results highlight distinct major pore types across various diagenetic states attributable to complex diagenesis. Specifically， the early diagenetic stages A and B evidenced the major pore types of residual pores by compaction and both intragranular pores from feldspar dissolution and intergranular pores from carbonate dissolution， respectively， while middle diagenetic stages A₁， A₂， and B witnessed the presence of dissolution pores at quartz edge， both intragranular pores from feldspar dissolution and intergranular pores from carbonate dissolution， and fractures， respectively as major pore types. As diagenesis advanced， residual pores by compaction， dissolution pores at quartz edge， and intragranular pores from feldspar dissolution grew increasingly hydrophilic. Furthermore， intergranular pores from calcite dissolution trended toward lipophilicity， while intergranular pores from dolomite dissolution evolved from water wetting to intermediate wetting. The overall wettability of the low-permeability sandstone reservoirs is governed by the major pore types and their surface wettability throughout the diagenetic timeline. The wettability of low-permeability sandstone reservoirs was dominated by water wettability across all the diagenetic stages， showcasing strong hydrophilicity， weak hydrophilicity， hydrophilicity， intermediate wetting， and hydrophilicity sequentially. Finally， a wettability evolution model of sandstone reservoirs under the action of diagenesis is established， which will guide the prediction of sweet spots in low-permeability sandstone reservoirs.

Evolutionary characteristics of sealing capacity of deep salt caprocks under temperature-pressure coupling

Shan ZHAO, Hua LIU, Xianzhang YANG, Yongfeng ZHU, Shen WANG, Ke ZHANG, Xin WEI

2023, 44(5): 1321-1332. doi:10.11743/ogg20230520

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Three sets of experiments， including constant temperature-variable-pressure， variable temperature-constant pressure， and temperature-pressure coupling， were executed to simulate the influence of temperature and pressure conditions on the evolution of salt rock cap sealing ability using the experimental device of high temperature and high pressure triaxial rock mechanics testing system on salt rock samples from Jintan Salt Cave， China. The results indicate that： ① The coupling effect of temperature and pressure leads to a significant reduction in short-term strength， significant enhancement of plasticity of salt rock， and shortening of brittle-to-plastic transition time. The percentage （T_i ） of short-term strength reduction of salt rock caused by temperature is greater than 35.06 % while the maximum short-term strength reduction percentage （P_i ） of salt rock caused by pressure is only 38.25 %， indicating that the mechanical properties of salt rock are mainly controlled by temperature during the burial process. ② Under a single pressure， salt rock fractures have a trend of gradually decreasing and healing； while under the coupling of temperature and pressure， the salt rock will experience a phenomenon of “re-cracking”， with pressure dominating the low temperature stage （temperature < 90 ℃） and temperature dominating the high temperature stage （temperature ≥ 90 ℃）， resulting in creep damage to the salt rock. ③ An evolutionary model of “brittleness—brittleness-plasticity—plasticity—creep damage—damage healing” was established for deep salt rocks. Under the coupling of temperature and pressure， the creep damage stage is extremely unfavorable for the preservation of oil and gas reservoirs under high temperature conditions. Therefore， accurately determining the evolution characteristics of salt rock sealing ability can provide a theoretical basis for analyzing the enrichment patterns of deep pre-salt oil and gas reservoirs.

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