Front. Earth Sci. Frontiers in Earth Science Front. Earth Sci. 2296-6463 Frontiers Media S.A. 1751792 10.3389/feart.2026.1751792 Original Research Favorable conditions for deep dissolution reservoirs in warm basins with stable source-to-sink systems: example from the eastern Pearl River Mouth Basin Li et al. 10.3389/feart.2026.1751792 Li Xiaoping 1 2 * Writing - original draft Writing - review and editing Liu Baojun 1 2 Conceptualization Writing - review and editing Li Xiaoyan 1 2 Writing - original draft Writing - review and editing Zang Qibiao 1 2 Writing - original draft Writing - review and editing Liu Jinliang 1 2 Writing - original draft Writing - review and editing Xiang Yushu 1 2 Writing - review and editing Tao Wenfang 1 2 Writing - original draft Cai Guofu 1 2 Writing - original draft Zhou Fengjuan 1 2 Writing - review and editing Shenzhen Branch of China National Offshore Oil Corporation Limited, Shenzhen, Guandong, China Deepwater Development Ltd., of CNOOC (China), Shenzhen, Guandong, China Correspondence: Xiaoping Li, lixp5@cnooc.com.cn 23 02 2026 2026 14 1751792 22 11 2025 22 01 2026 29 01 2026 Copyright © 2026 Li, Liu, Li, Zang, Liu, Xiang, Tao, Cai and Zhou. 2026 Li, Liu, Li, Zang, Liu, Xiang, Tao, Cai and Zhou https://creativecommons.org/licenses/by/4.0/ This is an open-access article distributed under the terms of the Creative Commons Attribution License (CC BY). The use, distribution or reproduction in other forums is permitted, provided the original author(s) and the copyright owner(s) are credited and that the original publication in this journal is cited, in accordance with accepted academic practice. No use, distribution or reproduction is permitted which does not comply with these terms.

Exploration results demonstrate the development of high-quality reservoirs with superior physical properties (porosity up to 22%, permeability up to 4 D) in the deep Paleogene strata of the eastern Pearl River Mouth Basin, despite burial depths greater than 3,500 m and formation temperatures exceeding 120 °C. Their formation is closely linked to dissolution by fluids. By integrating petrographic, geochemical, and basin analysis methods, this study identifies three principal types of dissolution fluids in the study area: meteoric water, organic acids, and hydrothermal fluids. Accordingly, three categories of dissolution reservoirs are delineated. The favorable geological conditions for each reservoir type are elucidated as follows: 1. Meteoric water dissolution reservoirs require prolonged shallow burial due to early tectonic uplift, early active faults serving as infiltration pathways, and sealing preservation provided by overlying thick mudstones. 2. Organic acid dissolution reservoirs are governed by a strong supply of organic acid sourced from hydrocarbon-rich sags, effective transport through late-stage active faults, and a close source-reservoir configuration. 3. Hydrothermal dissolution reservoirs are primarily associated with deep-seated faults (especially for NNW-trending concealed faults) penetrating the Moho, which act as conduits for hydrothermal fluid migration. This study clarifies that, within the context of a stable source-to-sink system and a warm basin setting, the differential distribution of deep high-quality reservoirs is predominantly controlled by the types of dissolution fluids and their specific geological conditions. Three conditions are the favorable geological conditions for their formation: 1. A stable source-sink system provides the material basis and dissolution channels for reservoirs; 2. Multi-source fluids are driving forces for the formation of reservoir improvement; 3. Tectonic activities provide channels and open environments for dissolution. These findings contribute to a deeper understanding of the genesis of deep reservoir and provide guidance for exploration in analogous basins.

 deep strata dissolution reservoir favorable geological conditions hydrothermal fluid meteoric water organic acid Paleogene Pearl River Mouth Basin National Major Science and Technology Projects of China 10.13039/501100013076 The author(s) declared that financial support was received for this work and/or its publication. This research was funded by the National “15th Five-Year Plan” Major Science and Technology Project “The mechanism of hydrocarbon accumulation and key technologies for exploration and development in the South China Sea” (2024ZD1402700). The major technical project of CNOOC Ltd “Genesis of High-Permeability Paleogene Reservoirs in Hydrocarbon-Rich Sags of Zhu I Depression” (SCKY-2025-SZ-YJYKT-08). section-at-acceptance Sedimentology, Stratigraphy and Diagenesis Introduction

As exploration extends into deeper strata, structural traps at shallow and intermediate depths are nearly exhausted. Consequently, the deep Paleogene has become a primary exploration target in the Cenozoic basins of eastern China. However, these Paleogene strata are typically deeply buried, commonly exceeding 3500 m (Feng et al., 2016; Xu et al., 2025), with formation temperatures often above 120 °C. Intensive diagenesis, generally reaching middle stages A2-B, leads to rapid deterioration of reservoir physical properties, with permeability frequently falling below 10 mD, such conditions make it difficult for reservoir productivity to meet commercial development requirements. Nevertheless, high-quality reservoirs do develop locally, influenced either by low geothermal gradients (Shi et al., 2024; Shou et al., 2006; Cao, 2021) or by anomalously high porosity and permeability zones resulting from fluid dissolution and alteration (Cao et al., 2022a; Sun et al., 2013; Yuan et al., 2013). The development of such high-quality reservoirs is key to unlocking the potential of deep Paleogene systems.

Studies have shown that the development of dissolution-type reservoirs exhibits obvious depth zonation (Cao et al., 2023; Xu et al., 2025): meteoric water dissolution dominates in the shallow burial stage (<2,000 m), organic acid dissolution is the core in the medium burial stage (2,000–4,000 m), and hydrothermal fluid dissolution or carbonic acid dissolution prevails in the deep burial stage (>4,000 m). Geothermal conditions control the intensity of dissolution by affecting chemical reaction rates and fluid properties, with the optimal dissolution temperature window being 80 °C–120 °C (i.e., the golden temperature zone, which is the optimum temperature for organic acid dissolution) (Nadeau et al., 2023).

Over the past decade, intensified exploration targeting Paleogene clastic rocks in the eastern Pearl River Mouth Basin (PRMB) has led to the discovery of reserves exceeding 500 million tons, establishing the deep Paleogene as the main exploration frontier in this region (Xu et al., 2024; Xu and Fan, 2021; Li et al., 2012; He et al., 2022). Similar to other eastern China Cenozoic basins, deep reservoirs here are generally buried deeper than 3,500 m with temperatures exceeding 120 °C, classifying the basin as a warm basin. During the Paleogene, the basin was characterized by a small areal extent and deep lacustrine conditions, with adjacent uplifts supplying stable sediment sources to the sags in various forms. These stable source-to-sink systems provided a robust material basis for reservoir formation (Cheng et al., 2022; Lei et al., 2023; Liu et al., 2025). Overall porosity ranges between 8% and 15%, with permeability below 10 mD, however, local reservoirs exhibit porosity near 20% and permeability around 100 mD. In 2024, within the study area under formation temperature > 120 °C and burial depth near 3,700 m, a reservoir with permeability as high as 4 Darcys was discovered (Xu et al., 2025). This reservoir displays well-developed dissolution pores and is preliminarily interpreted to have formed through diagenetic fluid alteration. Although the Pearl River Mouth Basin is similar to other basins in terms of geothermal temperature and burial depth, its reservoir improvement effect is rarely seen elsewhere (porosity is generally increased by 10% and permeability by 5% in most areas, while in this basin, porosity is doubled and permeability is increased by nearly 40 times). This type of high-quality reservoir is a primary target in deep exploration. However, to accurately delineate its distribution, it is essential first to clarify the main controlling factors of its formation and the favorable geological conditions, thereby providing a geological basis for distribution prediction.

Based on analytical data including seismic, tectonic, petromineralogical, and geochemical analyses, this paper characterizes the petrological and reservoir physical properties of these highly dissolved reservoirs. It also presents a systematic analysis of the types of corrosive fluids, dissolved minerals, and dissolution products, clarifies the petrographic thin section and geochemical test basis for dissolved reservoirs, reconstructs the dissolution process, and identifies the favorable geological conditions for dissolution. The purpose is to establish a systematic understanding of the external characteristics, genetic mechanisms, and favorable formation conditions of dissolved reservoirs, thereby providing a reference for the prediction of sweet spots in deep tight reservoirs.

 Geological background

The Pearl River Mouth Basin (PRMB), situated in the northern South China Sea, covers an area of nearly 300,000 km2, ranking it among the largest offshore petroliferous basins in China. The basin structure is dominantly controlled by a NE-trending fault system, which, together with NWW-trending faults, defines its uplift-depression framework, resulting in a structural grain characterized by N-S zonation and E-W segmentation. The northern part of the study area encompasses the Zhu I and Zhu III Depressions. From west to east, The Zhu I Depression includes the Enping, Xijiang, Huizhou, Lufeng, and Hanjiang Sags. The southern part is dominated by the Zhu II Depression, which contains the Kaiping and Baiyun Sags (Figure 1a).

Tectonic element division (a) and comprehensive stratigraphic column (b) of the Pearl River Mouth Basin. The black box indicates the location of Figure 5. Letters denote structural names, while combinations of letters and numbers represent well numbers (Map modified after Zhang et al., 2021).

Geological map and stratigraphic column of the Pearl River Mouth Basin region in southern China. Panel a shows basin boundaries, tectonic units, sags, massifs, uplifts, faults, and structural features with a geographical inset indicating the study area. Panel b presents a stratigraphic column correlating strata, seismic reflection interfaces, lithology, and tectonic events from the Paleogene to Quaternary, detailing rock types and major tectonic phases.

Influenced by the collision and compression between the Indian and Eurasian plates, as well as the subduction and compression of the Pacific Plate, the PRMB has experienced a unique tectonic stress history and a complex evolutionary record (Deng et al., 2020; Zhao et al., 2021; Zhang et al., 2023; Zhou et al., 2018; Fang et al., 2023; Larsen et al., 2018; Ding et al., 2020; Taylor, 2025; Li et al., 2017; Tang et al., 2017). During the Yanshanian period, the basin resided on an active continental margin. By the Cenozoic, following the retreat of the Pacific subduction zone, the South China continental margin transitioned from an Andean-type setting to an extensional, divergent passive margin. The basin exhibits a dual structure architecture, comprising a lower faulted sequence and an upper sag sequence. The stratigraphic column includes the Paleogene Shenhu, Wenchang, Enping, and Zhuhai Formations, overlain by the Neogene Zhujiang, Hanjiang, Yuehai, Wanshan Formations, and the Quaternary. Fluvial-lacustrine sedimentary systems developed during the deposition of the Eocene Wenchang and Enping formations. Starting in the Oligocene with the Zhuhai Formation, the basin underwent marine transgression; Quaternary deposition is represented mainly by shallow-marine shelf and slope to deep-water deposits (Figure 1b). This study focuses on the deep Paleogene succession, primarily the Wenchang and Enping Formations. During Wenchang Formation deposition, the basin was in a rapid rifting phase, characterized overall by an alternating uplift-sag pattern with narrow, deep lakes, reflecting a setting of widespread uplifts and small, isolated lake basins. Stable source-to-sink system supplied ample sediment from surrounding uplifts to the sags. Sand bodies were deposited predominantly as larger-scale braided river delta-fan delta-sub-lacustrine fan depositional systems (Xu et al., 2024; Xu and Fan, 2021; Li et al., 2012; He et al., 2022). The Enping Formation represents a transitional fault-sag phase, during which the basin gradually filled, developing widespread shallow lakes; reservoirs from this interval are composed mainly of shallow-water braided river delta facies. Basement lithology is predominantly granite, with sporadic volcanic rocks and sedimentary rocks (remnants of Late Cretaceous faulted basins) (Shi et al., 2014; Chen et al., 2003; Shi et al., 2017; Zhang et al., 2025).

 Data and methodology Seismic data

Three-dimensional seismic data were used for structural-stratigraphic analysis, covering nearly 300,000 km2of the entire study area. The dominant frequency of the main target formations (Wenchang Formation and Enping Formation) ranges from 20 to 60 Hz, corresponding to a seismic resolution of approximately 40–50 m. This enables high-precision imaging of strata and oil-gas reservoirs, and supports detailed sequence division of the Wenchang and Enping Formations, laying the foundation for this study.

 Petrological and mineralogical analysis data

Rock and mineral samples were collected from the Lufeng Sag, Huizhou Sag, Enping Sag, Kaiping Sag, and Baiyun Sag in the Pearl River Mouth Basin. A total of over 1,000 samples were analyzed, covering multiple key parameters. Sample analyses included: identification of cast thin sections and conventional physical property analysis to evaluate reservoir storage capacity; identification of cast thin sections, X-ray diffraction analysis, and scanning electron microscopy to reflect the mineralogical characteristics of the reservoirs (Cao et al., 2022a; Cao et al., 2022b; Liu et al., 2019; Yuan et al., 2013). Petrographic observation and geostatistical methods were employed to characterize reservoir properties and investigate the main controlling factors of the physical properties of high-quality dissolution reservoirs.

 Geochemical data

This study integrated petrology, geochemistry, and basin analysis methods. The geochemical data used include evaluation indicators such as fluid inclusions, oxygen isotopes of quartz overgrowths, carbon and oxygen isotopes of authigenic calcite, carbon dioxide gas isotopes, and vitrinite reflectance (Ro) of source rocks. Fluid inclusions can record homogenization temperatures and assist in identifying fluid types. Isotopes are used to determine the properties and sources of diagenetic fluids (Cao et al., 2022b; Liu et al., 2019; Yuan et al., 2013). Vitrinite reflectance (Ro) of source rocks reflects the thermal maturity of organic matter, aiding in determining the period of organic acid formation. Techniques such as basin modeling, fluid inclusion analysis, and well log response analysis were applied to identify multi-source fluid types and origins, and to clarify the types of dissolution reservoirs and the favorable geological conditions for their formation.

Data sources showed as following Table 1.

Summary table of data sources.

Data type Characteristics
Seismic Area: 300,000 km2; dominant frequency: 20–60 Hz; resolution: 40–50 m
Petro-mineral More than 1,000 samples, including cast thin section identification, conventional physical property analysis, X-ray diffraction analysis, and scanning electron microscope analysis
Geochemistry Fluid inclusions, oxygen isotopes of quartz overgrowths, carbon and oxygen isotopes of authigenic calcite, carbon dioxide gas isotopes, and vitrinite reflectance of source rocks
Results Characteristics of deep reservoirs

Core observations and thin section analyses indicate that the Paleogene lithology in the study area consists mainly of fine sandstone to sandy fine conglomerate. The sandstone types are predominantly lithic quartz sandstone and feldspathic litharenite (Figure 2). The average interstitial material content is 8%, comprising a matrix that is largely argillaceous and tuffaceous; cement types are diverse, primarily including clay minerals, carbonate, along with diverse cement types dominated by clay minerals, carbonate, and silica. Overall reservoir porosity ranges from 1% to 30%, mostly between 5% and 20%. Permeability varies from 0.001 to 4,660 mD, with most values between 0.01 and 500 mD, classifying the reservoirs as extra-low to medium in both porosity and permeability.

Triangular diagram of the Paleogene sandstone composition in the study area.

Ternary diagram classifying sandstone types based on three compositional endmembers: quartz (Q), feldspar (F), and lithic fragments (L). Data points are color-coded by sample group, and fields are labeled as quartz sandstone, feldspathic quartz sandstone, feldspathic lithic sandstone, and lithic sandstone, with key percentage boundaries indicated.

The relationship between reservoir physical properties and depth (Figure 3) clearly reveals an anomalously high porosity-permeability zone below 3,500 m, with porosity reaches 22% and permeability attains 4 Darcys. These values deviate significantly from the normal porosity-depth trend. Previous studies suggest that anomalously high porosity–permeability zones are commonly associated with the development of secondary porosity (Yuan et al., 2007; Yuan J. et al., 2017; Zhong et al., 2018; Chen et al., 2021). Microscopic examination of cores and thin sections from the study interval reveals a variety of pore types in the Paleogene clastic reservoirs. Primary pores are dominated by residual intergranular pores (Figure 4a), while secondary pores include intergranular dissolution pores, intragranular dissolution pores, and intercrystalline micropores (Figures 4b–d). This high porosity interval exhibits pronounced dissolution characteristics. Macroscopically, cores and sidewall cores samples show uneven mineral dissolution, with locally developed dissolution vugs up to 3 cm in diameter, distributed in irregular spots or concentrated patches (Figure 4e). In deeper buried-hill reservoirs, vugs can reach up to 6 cm (Figure 4f). Some dissolution fractures are filled with authigenic calcite (Figure 4g), and locally, well-formed quartz crystal clusters are observedgrowing within vugs (Figure 4h).

Porosity-Permeability relationship diagram of Paleogene Sandstone in the study area.

Two scatter plots compare porosity percentage and permeability in millidarcies versus burial depth in meters. Both charts display data series by color and symbol, representing different formations or wells, with depths ranging from one thousand five hundred to four thousand five hundred meters. Data points are densely clustered between three thousand and four thousand meters, and legends show distinct markers for formations such as Enping, Wenchang, and others.

Reservoir space types and dissolution characteristics in the study area. (a) L-1 well, 4,383.75 m, medium-fine grained lithic quartz sandstone, porosity 17.43%, permeability 43 mD, primary and dissolution pores, blue epoxy-impregnated thin section. (b) H-3 well, 4,117.88 m, sandy conglomerate, porosity 12.23%, permeability 170.03 mD, mainly primary pores with minor dissolution pores, blue epoxy-impregnated thin section. (c) E−27 well, 3,457 m, coarse-medium grained feldspathic litharenite, porosity 12.66%, permeability 1.26 mD, intragranular dissolution pores in K-feldspar, with intercrystalline micropores, SEM. (d) H-4 well, 4,317.4 m, sandy conglomerate, porosity 13%, permeability 447 mD, plagioclase dissolution vugs, nearly complete dissolution, pores are clean (within black dashed box), blue epoxy-impregnated thin section. (e) H-3 well, 4,315.76 m, coarse-grained feldspathic litharenite, porosity 11.8%, permeability 10.9 mD, locally distributed dissolution pores, core photo. (f) H-6 well, dissolution vug in granite porphyry, long axis up to 30 mm, aligned parallel to fracture, core photo. (g) H-4 well, 4,314.95 m, calcite vein within fracture (red arrow). (h) H-3 well, 4,316.7 m, quartz crystal cluster growing within dissolution vug. Note: In all blue epoxy-impregnated thin sections, blue areas represent pores. Well locations are shown in Figure 1.

Panel a shows a thin section under a microscope indicating residual intergranular and dissolution pores marked by arrows. Panel b highlights intergranular and intragranular dissolution pores in blue under a microscope. Panel c is a black-and-white scanning electron microscope image showing dissolution pores within feldspar grains and intercrystalline pores, both labeled. Panel d displays a blue-stained dissolution pore outlined by a dashed line in a thin section. Panel e includes a labeled core sample with a visible fracture and depth marker reading 4215.76 meters. Panel f presents a core sample with a prominent vertical red line and visible vuggy porosity. Panel g shows a thin section with a brightly colored vein filled with calcite, labeled accordingly. Panel h features a false-color mineral map highlighting quartz druse along the edge, with element abbreviations listed at the base. Dissolution reservoir types by fluids

The types of diagenetic dissolution fluids, along with the identity of dissolved minerals and associated processes, were determined through petrographic, micro-area geochemical (elemental/isotopic), and fluid inclusion analyses. Based on these results and the regional vitrinite reflectance (Ro) pattern, three main dissolution fluid types are identified: meteoric water, organic acids, and hydrothermal fluids (Figure 5). This study thus categorizes the dissolution-altered reservoirs into three types: meteoric water dissolution, organic acid dissolution, and hydrothermal dissolution reservoirs.

Distribution of dissolution fluids in the study area. Map location is indicated by the black box in Figure 1.

Geological map showing organic acids in green, meteoric water in yellow, and hydrothermal fluids in orange ovals, with tectonic boundaries, buried faults in red, and depression-controlled faults in blue; well points marked as red dots across labeled sags including Xijiang, Huizhou, Lufeng, Enping, Yangjiang, Kaiping, and Baiyun. Scale bar and north arrow included for orientation. Meteoric water dissolution reservoirs

The role of meteoric water in reservoir dissolution has long been a challenging research topic in clastic diagenesis. Although meteoric water is generally less acidic than organic acids, it operates in a relatively open system where dissolution products can be readily removed. Under subaerial conditions, dissolution can persist over prolonged periods, allowing time to compensate for its weaker acidity. Consequently, meteoric water is widely regarded as a key agent in reservoir dissolution (Ding et al., 2014; Liu et al., 2019; Mu, 2023; Rivers and Kaczmarek, 2020; Mansurbeg et al., 2006; Mansurbeg et al., 2012; Mansurbeg et al., 2020; Kseniya and Ilya, 2025; Yuan G. H. et al., 2017; Skeltona et al., 2019; Fekete et al., 2016; Zakharov et al., 2019; Yang et al., 2023; Tong et al., 2024; Ma et al., 2025). However, because meteoric dissolution typically occurs during eodiagenesis and the evidence is often erased by later diagenetic alterations in open environments, its recognition in the geologic record remains difficult (Huang et al., 2003). Recent advances in analytical techniques—such as oxygen isotope analysis of early cements and the integration of sequence stratigraphy with mineralogy—have provided new tools for identifying meteoric water dissolution (Ma et al., 2025; Chen, 2021; Wang et al., 2025; Su et al., 2017).

In the eastern PRMB, confirmed meteoric water dissolution reservoirs are primarily found in the well P-34 on the northern slope of the Baiyun Sag and the L structure in the Lufeng Sag (Figure 5) (Li et al., 2024; Liu et al., 2022). Thin sections reveal extensive feldspar dissolution with clean intergranular pores (Figure 6a), indicating an open diagenetic system where dissolution products were efficiently exported. Oxygen isotope values (δ18O) of quartz overgrowths decrease outward, ranging overall from 15.7‰ to 16.8‰ (Figure 6b). When cross-plotted with homogenization temperatures of fluid inclusions in the overgrowths, the data indicate that the diagenetic fluid had δ18O values lower than −4‰ (Figure 6c), consistent with meteoric water input. Moreover, in the L structure of the Lufeng Sag, at depths near 4,000 m, reservoirs exhibit porosity up to 14.6% and permeability up to 260 mD, Pore water salinity in these intervals is as low as 5,000 mg/L, significantly lower than typical formation water salinity (20,000 mg/L) (Figure 7a). In the low-salinity intervals, illite commonly occurs as honeycomb-shaped illite-smectite (I-S) mixed-layer clay, contrasting with the film-like illite filling intergranular pores in normal salinity intervals from adjacent wells (Figures 7b,c). This indicates relatively low diagenetic intensity, confirming that low-ion-concentration meteoric water retards the illitization process, thereby reducing pore-throat blockage by clay minerals and helping preserve favorable reservoir quality.

Reservoir characteristics and identification evidence for meteoric water dissolution reservoirs. (a) P-34 structure, 4,407.1 m, coarse sandstone, feldspar dissolution moldic pores, clean intergranular space, blue epoxy-impregnated thin section, blue represents pores. (b) Oxygen isotope distribution across quartz overgrowths. (c) Cross-plot of quartz overgrowth δ18O values and fluid inclusion homogenization temperatures; intersection points lie within the black box.

Panel a shows a photomicrograph of a mineral thin section with blue and red stained regions, scale bar 200 micrometers. Panel b displays a grayscale microscopic image with labeled quartz grain and overgrowth boundaries, isotopic values, and an inset of a stained thin section. Panel c presents a contour graph relating quartz oxygen isotope values to fluid temperature with labeled axes and boxed data range.

Characteristics of low-salinity strata in the L structure. (a) Low-salinity formation in the L structure overlain by nearly 100 m thick mudstone; red arrow indicates location of (b); blue arrow indicates location of (c). (b) Honeycomb-shaped I-S mixed-layer in low-salinity formation of well L-1, depth 4,155 m, burial depth 3,932 m, formation temperature 148.3 °C, porosity 10%, permeability 2.0 mD. I/S:mixed-layer illite-smectite. Depth location shown by red arrow in (a). (c) Filmy I-S mixed-layer in normal salinity formation of well L-3, depth 4,111 m, burial depth 3,938 m, formation temperature 147 °C, porosity 11%, permeability 0.37 mD.I:illite, Q:quartz Depth location shown by blue arrow in (a).

Panel a features well log correlation charts for wells L-1 and L-3, indicating formations, lithology, gamma ray and density measurements, and highlighting low and normal salinity reservoirs near 4100 meters, with a legend for sediment types. Panel b displays a scanning electron microscope image of porous mudstone from well L-1, showing interlayered clays labeled as I/S. Panel c presents a scanning electron microscope image from well L-3, depicting quartz grains labeled Q and intergranular material labeled I. Organic acid dissolution reservoirs

Organic acids represent the predominant type of dissolution fluid in the study area. Within the major source rocks, the Wenchang and Enping Formations, organic acids show the most extensive lateral distribution (Figure 5), and correspondingly, organic acid dissolution reservoirs are widely developed throughout the basin (Zhang et al., 2025; Hao et al., 2011; Yuan et al., 2025; Gonzalez-Betancourt et al., 2022; Pang et al., 2023; Hu et al., 2025; Long et al., 2011; Zhu M. et al., 2019; Zhu X. M. et al., 2019). Taking the H structure in the Huizhou Sag as an example, high-quality reservoirs occur at burial depths reaching 3,700 m, high-quality reservoirs here can have permeabilities up to 1,090 mD, with permeabilities as high as 1,090 mD, an average porosity of 12.9%, and a maximum porosity of 18.1%. The reservoir lithology is mainly gravel-bearing coarse feldspathic litharenite, exhibiting abundant intergranular and intragranular dissolution pores (Figures 4a,b), indicating intense dissolution during diagenesis. The dissolved minerals are predominantly feldspars, with minor amounts of calcite and tuffaceous material locally.

Thin sections reveal residual organic matter in reservoir samples after oil and salt washing and SEM images show organic matter occurring intergranularly (Figure 8a). Meanwhile, a cross-plot of carbon and oxygen isotopes from authigenic calcite falls within the field indicative of an origin via organic acid decarboxylation (Figure 8b), further reflecting the activity of organic acids. Analysis of reservoir pores in adjacent wells shows that dissolution intensity increases progressively from areas distal to the sag center toward more proximal locations, with dissolution pore area ratio increasing from an average of 0.1%–2.0% to 8.8% (Figure 8c). Vertically, the size and density of dissolution pores gradually decrease from deeper to shallower intervals (Figure 8c), indicating weakening dissolution upward.

Organic acid dissolution characteristics of the Wenchang Formation reservoir in the H structure. (a) H-1, 4,317.07 m, banded organic matter (red arrow). (b) Cross-plot of carbon and oxygen isotopes from authigenic calcite. (c) Proportion of dissolution pores at different locations relative to the sag center; the rightmost well is closest to the sag center and shows the highest dissolution pore proportion. Note that dissolution pore proportion decreases from deep to shallow.

Panel a displays a thin-section micrograph with black organic matter and a red arrow indicating a feature of interest. Panel b shows a bivariate scatter plot with data groupings for cements and calcite veins, axes labeled δ13C and δ18O, with reference fields for inorganic carbon and sedimentary organics. Panel c presents three bar charts comparing primary, secondary, and micro pore content percentages by depth for three wells, labeled H-1, H-2, and H-3, using green, red, and gray bars. Hydrothermal dissolution reservoirs

The impact of hydrothermal fluids on reservoir alteration remains debated. Some studies suggest that elevated hydrothermal temperatures accelerate reservoir densification, and that ions carried by such fluids may precipitate upon saturation, thereby reducing porosity and permeability (Li et al., 2025; Sun et al., 2020; Jiang et al., 2018; Hou et al., 2019). Conversely, other researchers argue that acidic components (e.g., CO2 and H2S) dissolved in hydrothermal fluids can significantly alter the mineralogy, texture, and chemical composition of host rocks, leading to dissolution of various minerals (Shi et al., 2007; Tang et al., 2018; Salih, 2023; Lei et al., 2018; Mansurbeg et al., 2024; Xu et al., 2024; Chen et al., 2025; Mohammadi, 2025; Zhao and Yi, 2022; Zhang et al., 2024; Maciel et al., 2024; Menezes et al., 2019; Salish, 2023). In the study area, evidence including hydrothermal minerals, anomalous high fluid inclusion homogenization temperatures, inorganic origin CO2, and anomalous carbonate C–O isotopes collectively indicates that deep Paleogene reservoirs have been affected by deep-sourced hydrothermal fluids.

In terms of dissolution products, hydrothermal minerals such as barite, saddle dolomite and pyrite are observed in Paleogene reservoir thin sections under microscope and SEM. Barite occurs in two forms: filling intragranular dissolution pores in feldspars (typically strip-shaped) and occupying intergranular pores (typically plate-shaped) (Figures 9a,b). Saddle dolomite mainly fills intergranular spaces (Figure 9c). Pyrite crystals are relatively euhedral, ranging from idiomorphic to subidiomorphic, and occur mainly as pentagonal dodecahedrons and cubes (Figures 9d,e). These crystal morphologies differ from microgranular or framboidal pyrite and are typically indicative of hydrothermal formation at temperatures of 200 °C–300 °C (Zhu et al., 2025).

Characteristic plate of hydrothermal minerals. (a) K-11, 4,163 m, barite with good crystal form (red arrow) in feldspar dissolution moldic pore. (b) K-18, 2,794.3 m, barite filling between quartz grains, almost completely occupying the pore (red arrow). (c) E−27, 4,063.8 m, Enping Formation, saddle dolomite visible (red arrow). (d) K-18, 3,575 m, Wenchang Formation, pentagonal dodecahedron pyrite visible (red arrow). (e) K-18, 3,539.1 m, Wenchang Formation, cubic pyrite visible (red arrow).

Panel a shows a thin section under a microscope with blue-stained mineral grains and red arrows pointing to linear features; panel b displays a dark field view with crystalline grains and a red arrow highlighting a boundary; panel c presents a microscope image of fine-grained blue and brown minerals with a red arrow pointing to a foliation or fracture; panel d is a scanning electron microscope image of crystalline minerals along a dashed line marking a boundary; panel e is a scanning electron microscope image of a large, striated crystal labeled 'Py' with a red arrow indicating a feature on its surface, surrounded by smaller labeled grains.

In addition, CO2 content in some oil-bearing intervals reaches 80%, with δ13C values consistent with a mantle-derived origin (Figure 10), This suggests that CO2-rich hydrothermal fluids migrated upward along faults and promoted feldspar dissolution in reservoirs. By products such as kaolinite was subsequently removed, contributing to the development of hydrothermal dissolution reservoirs in the region.

Carbon dioxide gas isotope discrimination chart.

Scatter plot showing CO2 percentage on the y-axis and δ13CO2 (per mil) on the x-axis, with colored dots representing samples from Huizhou (yellow), Kaiping-Yangjiang (red), and Lufeng (blue). Data points fall within regions labeled Organic, Mixed with organic and inorganic, Mantal Voganic/Magmatic, and Crustal Metamorphiccarbonate, highlighting distinct geochemical sources. Sequence of multi-fluid coupling

While previous analysis focused on evidence of individual fluid activities, it is undeniable that dissolution reservoirs are often the combined result of multiple fluid events. Although evidence of early fluid activity is frequently obscured or erased by later fluids, making the reconstruction of fluid activity sequences challenging, traces of these events can still be identified through geological analysis of geochemical characteristics of dissolution products, fluid inclusion temperatures, and the timing of large-scale organic acid expulsion during hydrocarbon generation.

Based on burial history analysis of various structures, along with diagenetic mineral and geochemical analyses, we have reconstructed the sequence of diagenetic fluid activities. Taking the P-34 structure as an example (Figure 11), in addition to the influence of early meteoric water, there is evidence of hydrothermal fluids, organic acids, and hydrocarbon fluids. This has led to a dissolution fluid sequence of early meteoric water, followed by hydrothermal fluids, and later organic acids and hydrocarbons, with hydrothermal dissolution occurring before organic acid dissolution. In contrast, the E-27 structure (Figure 12) experienced a sequence of early organic acid dissolution followed by late hydrothermal dissolution, with no evidence of meteoric water dissolution.

Burial history and fluids sequence of P-34 structure.

Burial history graph showing depth in meters versus age in millions of years with temperature contours from forty to one hundred eighty degrees Celsius, Vitrinite Reflectance (Ro) color zones, and strata labels for Neogene, Zhuhai, and Enping. Diagram includes syn-diagenetic, early, and middle diagenesis stages, with opennesse shifting from open to sealed, meteoric, thermal, and organic acid fluids indicated at different burial stages.

Burial history and fluids sequence of E-27 structure.

Burial history graph showing age versus depth for four strata: Neogene, Zhuhai, Enping, and Wenchang. Colored regions represent thermal maturity stages of Ro: green for 0.5-0.7 percent, yellow for 0.7-1.3 percent, and orange for 1.3-2 percent. Temperature contours range from forty to one hundred sixty degrees Celsius. Diagram indicates diagenesis stages, openness (open to sealed), organic acid activity (cyan arrow in early diagenesis), and thermal fluid presence (magenta arrow in middle diagenesis).

Thus, although the timing and sequence of different fluid activities may vary, their combined effects have effectively improved reservoir quality.

Next, we will analyze the favorable geological conditions for the development of dissolution reservoirs influenced by different fluids and attempt to identify common geological factors across these fluids. This will provide guidance for predicting such reservoirs.

 Discussions Favorable geological conditions of different fluids Favorable geological conditions for meteoric water dissolution reservoirs

Integrating paleogeomorphological, fault, and sedimentary characteristics, the following geological conditions are inferred to favor meteoric water dissolution in the P-34 structure:

Prolonged shallow burial during early diagenesis. Meteoric water can penetrate to depths of up to 2,000 m (Cao et al., 2022b). In this area, the Enping Formation remained buried at shallow depths (∼1,500 m) for an extended period during deposition of the overlying Zhuhai Formation (Figure 11). This prolonged shallow burial under weak compaction helped preserve primary porosity and allowed sufficient interaction with infiltrating meteoric water.

Early fault activity connecting reservoirs to the surface. Intensive early faulting in the study area, which continued into the Zhuhai Formation, provided effective conduits for rapid infiltration of meteoric water, promoting dissolution in the reservoirs (Que et al., 2023).

Thick sealing mudstones overlying reservoir intervals. In the L structure, The Wen 5 Member is overlain by approximately 100 m of thick, regionally extensive mudstone (Figure 7a), which effectively isolated the underlying reservoir from later formation water influx. This sealing allowed early low-salinity meteoric water to be preserved, slowing illite evolution and thereby maintaining reservoir porosity and permeability (Figure 13).

Model diagram of meteoric water dissolution.

Diagram illustrating a faulted geological cross-section with labeled sand and mudstone layers, a vertical well labeled L-3, meteoric water entry, atmospheric precipitation, arrows for uplift direction, and a legend explaining symbols for fault, sand, mud, uplift, and water. Favorable geological conditions for organic acid dissolution reservoirs

The distribution of organic acid dissolution reservoirs is primarily controlled by the intensity of organic acids and the effectiveness of migration pathways. Organic acid intensity is influenced by the hydrocarbon generation potential of the sag and the proximity to the source rock. Overpressured, hydrocarbon-rich sags facilitate the expulsion of large volumes of organic acids, thereby enhancing dissolution. Currently, the strongest organic acid dissolution reservoirs in the eastern PRMB are found in the Huizhou Sag, which is attributed to its high hydrocarbon generation capacity and inferred overpressure in the generation center (Hao et al., 2011; Chen et al., 2016; Wang, 2010). In addition, late-stage fault activity enables the migration of organic acids generated from source rocks into reservoirs. The migration pathways of organic acids are a key research focus, with faults and unconformities widely recognized as effective conduits (Luo et al., 2024; Qu et al., 2015; Jin and Yu, 2011; Guo et al., 2017). Analysis of dissolution vugs in organic acid dissolution reservoirs shows that their distribution is clearly fault-controlled, generally aligned along faults and oriented parallel to the fault trend (Figures 14a,b). Vugs located away from faults are significantly smaller, underscoring the critical role of faults in organic acid migration. Further reservoir analysis reveals that organic acid dissolution in the H structure exhibits a distinctly localized distribution. In the H-3 well, a strong dissolution zone approximately 100 m thick is observed, with porosity up to 22% and permeability up to 4 Darcys, significantly higher than in the overlying and underlying strata. The localized nature of this dissolution zone is closely related to the source rock on the opposite side of the fault (Figure 14c). Lithological correlation across the fault indicates that sandstones in this zone are juxtaposed against approximately 100 m of Wenchang Formation mudstone, which has an average TOC of ∼ 1.98%, an average Hydrogen Index (HI) of 208 mg/g, and type I–II1 organic matter, representing the main source rock in the Huizhou Sag. The main phase of organic acid expulsion occurred around 16 Ma (Xu et al., 2025), when the reservoir was buried to about 1,500 m depth, during the eodiagenetic stage—consistent with the well-preserved primary pores in the strong dissolution zone. The distribution of this anomalously high porosity-permeability interval confirms that close source-reservoir juxtaposition is a key favorable condition for the development of organic acid dissolution reservoirs (Figure 14c).

Types of organic acid dissolution on the well H-4. (a) Core of well H-4; (b) Sketch of the dissolved pores on the wells; (c) Model of organic acid dissolution.

Panel a shows a photograph of a cylindrical sandstone core marked at depth 4216.97 meters. Panel b presents a geological illustration indicating pebbly coarse sandstone, middle to coarse sandstone, fractures, and dissolution pores. Panel c depicts a cross-sectional reservoir model with labeled features, including a well, sand body, mudstone, high permeable reservoir, faults, strong hydrocarbon source rock, and organic acid migration pathways. Color-coded legends for both panels are included for reference. Favorable geological conditions for hydrothermal dissolution reservoirs

We selected samples representing varying CO2 contents in hydrothermal fluids and corresponding mineral dissolution degrees. A preliminary analysis of their relationship suggests a positive correlation, as can be observed from the Figure15a. Since these CO2 come from deep boundary of crust and mantle,the activity of hydrothermal fluids full of CO2 requires migration from depth to shallower levels via deep, large-scale faults. The PRMB contains two sets of such large faults: NE-NEE and EW-NWW trending (Figure 5). The NE–NEE trending faults are primarily basin-controlling structures that were highly active during the Wenchang Formation deposition and remained activity afterward, mostly cutting to the Conrad discontinuity. The EW-NWW trending faults are active mainly at later stages, locally influenced by the reactivation of similarly oriented concealed faults. These concealed faults extend to the Moho, providing pathways for mantle-derived fluids to ascend into reservoirs. Therefore, zones with such concealed faults are also active areas for deep hydrothermal fluid flow. Both fault systems were active during the hydrocarbon accumulation period, facilitating the upward migration of deep thermal fluids from the crust or mantle into Paleogene reservoirs and promoting dissolution (Figure 15b). As a result, hydrothermal dissolution reservoirs are typically developed near deep, large faults, and their vertical distribution is mainly correlated with periods of intense fault activity.

Types of hydrothermal dissolution on the well E-27. (a) Crossplot Diagram Showing the Relationship between Mantle-derived CO2 and Dissolution Porosity; (b) Formation model diagram of hydrothermal dissolution reservoirs.

Panel a shows a scatter plot relating mantle-derived CO2 percentage to dissolution porosity, with data grouped by location: Huizhou in yellow, Kaiping-Yangjiang in red, and Lufeng in blue; higher CO2 percentages correspond to greater porosity. Panel b is a labeled diagram illustrating subsurface geological structures, including sand body, mudstone, mantle, magma chamber, faults, hydrothermal fluids, Moho boundary, and an active fault near Well E-27, referenced by color-coded legend. Favorable geological conditions for dissolved reservoirs

To conduct a more comprehensive analysis of the characteristics of dissolution reservoirs, we performed a statistical analysis of these high-quality reservoirs from multiple perspectives, including their structural location, sedimentary environment, physical properties, mineral composition, burial depth, formation temperature, and fault characteristics, in order to clarify the specific features of the high-quality reservoirs.

Based on regional exploration experience, the lower limits for effective oil productivity in deep offshore reservoirs are porosity >8% and permeability >3 mD. These parameters are derived directly from production practice (Xu et al., 2024; Xu et al., 2025). For the dissolution reservoirs studied in this paper, both porosity and permeability generally exceed these thresholds, making them “sweet spot” reservoirs in exploration (Table 2).

Parameter threshold of effective dissolved reservoir.

Parameters Threshold Example
Well H-4 Well K-11 Well L-3 Well P-34 Well E−27
Location \ The upthrown side (footwall) of the fault corresponds to a paleo-uplift The downthrown side (hanging wall) corresponds to a paleo-high The downthrown side (hanging wall) corresponds to a paleo-high The downthrown side (hanging wall) corresponds to a paleo-high The downthrown side (hanging wall) corresponds to a paleo-high
Depositional facies \ Lacustrine beach-bar Subaqueous distributary channel Subaqueous distributary channel Subaqueous distributary channel Subaqueous distributary channel
Fault juxtaposition lithology \ Muddy source rock Sandstone Sandstone Sandstone Sandstone
Lower limits of porosity/% >8 5.9–18.112.9 3.6–16.811.3 6.0–17.412.4 8.0–14.612.5 11.8–14.714.3
Lower limits of permeability/mD >3 0.01–1,19055 0.01–15612 0.03–147.518.9 3.0–96 1.5–5.83.9
The strike of trap-controlling faults NE or NNW NNW NE NE NE NNW
Distance to fault/km <1.5 0.15 0.9 0.75 0.4 0.35
Growth index >1 1.2 1.3 1.25 1.15 1.2
Temperature/°C 120∼150 137 144 142 122 170
Burial depth/m 3,500∼4,500 3,700 3,500 3,850 4,250 4,780
Content of feldspar and lithics/% 25∼45 30.5–5444.5 27.6–6943.4 12–4021.4 25–6046 10–3621

Regarding faults, three indicators were selected to characterize them: the strike of trap-controlling faults, the distance from the target layer to the fault, and the fault growth index. Fractures serve as important pathways for fluids to enter and dissolve reservoirs. Specifically, NE-trending blind faults and NNW-trending late-stage active faults play key roles in connecting deep hydrothermal fluids and transporting late-stage fluids and hydrocarbons, respectively. Therefore, faults with these strikes were prioritized as primary factors. Second, the effective distance of fluid migration from faults into reservoirs is limited. Generally, closer proximity to faults corresponds to more abundant fluid activity. Distance analyses in three well areas (H-3, K-11, L-3) showed values within 1 km. Combined with literature research (Jiang et al., 2025), the effective fluid activity distance can extend up to 1.5 km, so 1.5 km was selected as the threshold. As for the fault growth index, late-stage or long-term active faults tend to remain open, facilitating fluid entry into reservoirs and product removal, making them effective migration pathways. Thus, faults with a growth index greater than 1 were set as the favorable threshold. The three key structures listed in the table all meet this criterion.

Regarding burial depth and temperature, these two factors are interrelated. In this region, dissolution reservoirs generally develop at temperatures between 120 °C and 150 °C, with burial depths ranging from 3,500 m to 4,500 m.

In terms of mineral content, dissolution fluids primarily affect feldspar and rock fragments. Higher contents of these minerals increase the availability of soluble material. Based on local characteristics of feldspar and rock fragment content, a range of 25%–45% is considered appropriate.

Thus, we believe that the following three conditions are the favorable geological conditions for their formation: 1. A stable source-sink system provides the material basis and dissolution channels for reservoirs. The Paleogene Wenchang Formation and Enping Formation in the Pearl River Mouth Basin develop a stable source-sink system with a high overall sand content and strong formation brittleness. Under the later differential uplift and faulting, they are likely to become fluid channels, thereby providing channels for improving reservoir quality. 2. Multi-source fluids are driving forces for the formation of reservoir improvement. We have clarified the sources, dissolved minerals, diagenetic environments, and reservoir contributions of three types of fluids: meteoric water, organic acids, and hydrothermal fluids. Although the distribution range and action period of different fluids vary, under the comprehensive action of these fluids, the reservoirs have the conditions for dissolution. 3. Tectonic activities provide channels and open environments for dissolution. The continuous differential tectonic uplift and subsidence as well as late-stage activities in the Pearl River Mouth Basin provide migration channels for fluid ascent. More importantly, the pores in some dissolved reservoirs are very clean, indicating that during the tectonic activities, the diagenetic environment tended to be open, and the dissolution products were then carried away from the reservoirs. The coupled effect of the above sufficient material sources, multi-source fluids, and the open environment brought by continuous tectonic activities has formed a strong dissolution improvement situation in the Pearl River Mouth Basin.

 Implication for dissolution reservoir exploration

Petroleum exploration in eastern China has generally entered the deep and ultra-deep layers of fault basins. Reservoir physical properties are the key to productivity release, and high-quality reservoirs modified by fluid dissolution are the preferred targets for exploration. Based on an analysis of laboratory data, this study conducts a comparative investigation of the petrological, mineralogical, and elemental geochemical characteristics of three types of fluids in the eastern Pearl River Mouth Basin—meteoric water, organic acids, and hydrothermal fluids. The favorable geological conditions for reservoir dissolution associated with each fluid type have been clarified.

In particular, regarding hydrothermal dissolution reservoirs, conventional views generally regard hydrothermal activity as predominantly destructive—a diagenetic process to be avoided in hydrocarbon exploration. However, in this study area, by establishing the relationship between CO2 and reservoir physical properties, we have demonstrated that deep mantle-derived CO2 can enhance reservoir porosity and permeability through dissolution, thereby providing a case for the constructive role of hydrothermal activity.

Furthermore, by comparing the favorable dissolution characteristics of different fluids, it can be seen that the coupling between fault activity and fluid flow is a key condition for fluids to play a constructive role in reservoir development. This may be attributed not only to faults providing pathways for fluid migration but also to the open environment created by fault activity, which facilitates the effective removal of dissolution products and ultimately leads to the formation of high-porosity and high-permeability reservoirs.

However, the research on dissolved reservoirs is affected by the diversity of dissolved fluids, long action time, and multi-stage transformation, making it difficult to restore dissolved fluids and determine the main controlling factors, which is significantly complex. Especially for sags with a relatively high geothermal gradient, deep reservoirs become dense faster, and thus require later tectonic and fluid actions to improve the reservoirs. This research can provide useful references for deep oil and gas exploration.

 Conclusion

Anomalously high-porosity and high-permeability reservoirs occur in the deep Paleogene strata of the Pearl River Mouth Basin. Their development is closely linked to dissolution and alteration by various fluids. Three main types of dissolution fluids are recognized—meteoric water, organic acids, and deep-sourced hydrothermal fluids, —which correspond to three distinct categories of dissolution reservoirs.

The formation of meteoric water dissolution reservoirs is favored by a combination of early tectonic uplift and shallow burial, early faulting that connected the reservoir to atmospheric water, and overlying strata dominated by thick mudstone with thin sandstone units. These conditions collectively facilitate and preserve evidence of meteoric water infiltration and dissolution.

Organic acid dissolution reservoirs develop under conditions including high source rock hydrocarbon generation potential, active faulting during hydrocarbon accumulation that links source rocks with reservoirs, and close source–reservoir juxtaposition. These factors collectively enable the delivery of organic acids and the intensification of dissolution.

Hydrothermally dissolution reservoirs are spatially and genetically associated with deep-seated, large-scale faults. In particular, E–W to NWW-trending concealed faults serve as key pathways for ascending hydrothermal fluids. Long-active sag-controlling faults also provide effective conduits for the upward migration of such fluids.

Data availability statement

The original contributions presented in the study are included in the article/supplementary material, further inquiries can be directed to the corresponding author.

 Author contributions

XpL: Writing – original draft, Writing – review and editing. BL: Conceptualization, Writing – review and editing. XyL: Writing – original draft, Writing – review and editing. QZ: Writing – original draft, Writing – review and editing. JL: Writing – original draft, Writing – review and editing. YX: Writing – review and editing. WT: Writing – original draft. GC: Writing – original draft. FZ: Writing – review and editing.

 Conflict of interest

Authors XpL, XyL, QZ, JL, YX, WT, GC, and FZ were employed by Shenzhen Branch of China National Offshore Oil Corporation Limited. Authors XpL, XyL, BL, QZ, JL, YX, WT, GC, and FZ were employed by Deepwater Development Ltd., of CNOOC.

The author(s) declared that this work received funding from CNOOC Ltd. The funder had the following involvement in the study: analysis, interpretation of data.

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Edited by: Jiawang Ge, Southwest Petroleum University, China

Reviewed by: Omar A. M. Mohammad, University of Kirkuk, Iraq

Qianghu Liu, China University of Geosciences Wuhan, China

Yuanfu Zhang, China University of Geosciences, China