Reservoir heterogeneity between intra-platform and platform-margin settings in an isolated carbonate platform: a case study from the carboniferous, Pre-Caspian Basin

Introduction: The Carboniferous isolated platform carbonate reservoirs in the Pre-Caspian Q6 Basin exhibit pronounced heterogeneity, which significantly constrains the effective prioritization and optimization of exploration targets. This study aims to elucidate the differential characteristics and genetic mechanisms of intra-platform and platform-margin reservoirs within the Carboniferous Unit 1 isolated carbonate platform in the southern Pre-Caspian Basin.

Methods: By integrating core and thin-section observations with porosity, permeability, mercury injection capillary pressure (MICP) data, and production performance analysis, we systematically compared the reservoir properties of the two settings.

Results: The results indicate that reservoir differentiation is primarily controlled by differential karstification within a unified depositional framework. Although both intra-platform and platform-margin settings exhibit comparable lithologies (mainly grainstones and packstones), their pore structures differ significantly. Intra-platform reservoirs are dominated by matrix porosity (e.g., selective dissolution pores) and show favorable porosity-permeability relationships. In contrast, platform-margin reservoirs develop heterogeneous fracture-vug systems, resulting in poor porosity-permeability correlations, while conventional core analysis systematically underestimates their actual flow capacity. Distinct karstification processes govern this spatial heterogeneity: facies-controlled penecontemporaneous dissolution shapes matrix porosity in intra-platform areas, whereas superimposed multi-phase coastal karstification creates complex fracture-vug networks along the platform margin. A differential pore evolution model is established to illustrate these mechanisms.

Discussion and Conclusion: These findings highlight the critical role of differential karstification in the diagenetic pathways of carbonate reservoirs. They not only elucidate the genetic mechanisms behind reservoir quality differences but also offer practical implications for reservoir evaluation and provide a robust theoretical foundation for predicting high-quality carbonate reservoirs in the study area and analogous geological settings.

1 Introduction

Carbonate platform reservoirs constitute pivotal targets in global hydrocarbon exploration. A comprehensive understanding of the differentiation of physical characteristics between platform-margin and intra-platform reservoirs has been developed. Numerous studies have demonstrated that platform margins typically possess a “triple advantage” of elevated porosity, high permeability, and superior connectivity. This phenomenon is primarily attributed to the development of reef-shoal complexes (commonly exhibiting single-layer thicknesses of 30–50 m) under high-energy hydrodynamic regimes, in conjunction with multi-stage dissolution processes (Lucia et al., 2007; Li et al., 2011; Zhao et al., 2014). For instance, in the Ordovician platform margins of the Tarim Basin, fracture densities can reach 15 fractures per meter, with centimeter-scale karst cavities frequently observed (Zeng et al., 2010; Liu et al., 2009; Gao et al., 2015). In the Sichuan Basin, the mean permeability of platform-margin reservoirs in the Leikoupo Formation is approximately 10 mD, considerably exceeding that of intra-platform micritic limestones (1 mD) (Huang et al., 2020; Che et al., 2018; Guo et al., 2014; Tan et al., 2014). By contrast, intra-platform reservoirs commonly exhibit substantial primary porosity degradation—exceeding 60%—due to early-stage compaction and cementation, accompanied by pronounced variability in fracture permeability (Al-Jehani et al., 2015; Tian et al., 2017). This observational pattern has been corroborated by classic case studies worldwide, including the Mishrif Formation in Iraq, the Changxing Formation in the Sichuan Basin, the Upper Ordovician of the Tazhong Oilfield, and Jurassic strata in the Middle East (Ehrenberg et al., 2006; Yu et al., 2024; Ma et al., 2012; Yunfeng et al., 2018; Zhiqian et al., 2015). These differences result in distinct exploration potentials. Owing to their “triple advantages,” platform margins have emerged as the preferred exploration foci in deep carbonate hydrocarbon systems (Yang and Zhu, 2011; Zhao et al., 2018), whereas the economic viability of intra-platform reservoirs relies heavily upon advanced fracture-cavity prediction technologies (Yu et al., 2024). This contrast further underscores the necessity for in-depth investigations into reservoir heterogeneity between intra-platform and platform-margin settings.

However, current models are predominantly derived from attached carbonate platforms and may not fully account for the distinct sedimentary architecture and diagenetic evolution of isolated carbonate platforms. The genetic mechanisms controlling reservoir-quality differentiation in such isolated settings remain poorly constrained, constituting a critical knowledge gap in predicting carbonate reservoirs. This study addresses explicitly this gap by investigating the atypical reservoir distribution within an isolated carbonate platform, thereby refining the conventional platform model.

The Unit 1 reservoir of the Carboniferous isolated carbonate platform in the southern Pre-Caspian Basin presents a unique and important case study. It demonstrates a trend that contradicts the established model: intra-platform reservoirs show better physical properties (average porosity: 8.56%; permeability: 3.071 mD) than platform-margin zones (porosity: 3.73%; permeability: 2.046 mD). This unexpected observation challenges the prevailing model of reservoir differentiation seen in most global carbonate platforms and suggests a distinct mechanism of sedimentary and diagenetic coupling within isolated platforms. Key unresolved questions arise, including whether the restricted hydrodynamic regime of isolated platforms inhibits the formation of high-energy facies along their margins, and whether intra-platform domains preserve greater porosity as a consequence of weaker early cementation or preferential migration of dissolution fluids. Moreover, a systematic understanding of the primary controls on reservoir differentiation within isolated platforms—particularly the interactions between sedimentary environments, diagenetic processes, and differential pore evolution—is still limited and requires further investigation.

Elucidating the controls behind this anomalous reservoir quality distribution is not only of fundamental scientific interest for understanding isolated platform evolution but also of direct practical importance. Accurate prediction of high-quality reservoir zones is essential for reducing exploration risk and optimizing development strategies in under-explored isolated carbonate plays, such as those in the Pre-Caspian Basin and similar regions around the world.

This study centers on the Carboniferous Unit 1 reservoir located in the southern Pre-Caspian Basin. By integrating data from core samples, well-logging, reservoir petrophysical analyses, and production metrics, we systematically characterize the intra-platform and platform-margin carbonate reservoirs within the Unit 1 reservoir group. We evaluate the genetic processes and controlling mechanisms that influence these reservoirs and propose a differential pore-evolution model for the two depositional settings. The findings will provide a new genetic framework for reservoir development on isolated carbonate platforms and offer actionable theoretical insights to support enhanced strategies for hydrocarbon exploration and development in this and similar geologic settings.

2 Geological setting

The Pre-Caspian Basin is situated along the southeastern margin of the East European Platform and is recognized as one of the world’s largest deep depression basins (Ross and Ross, 1985). Elongated east-west and exhibiting an approximately elliptical geometry, the basin encompasses an area of about 550,000 km² and contains a sedimentary succession reaching up to 22 km in thickness (Liu et al., 2003; Zempolich et al., 2002). It is bounded to the east and southeast by the Ural Orogenic Belt and the South Emba Fold Belt, respectively. At the same time, it transitions northward into the Volga-Ural Basin and extends southward toward the Caspian Sea. Internally, the basin is subdivided into four principal tectono-structural domains: the northern and northwestern fault-terrace zone, the central depression, the Astrakhan-Aktyubinsk Uplift Zone, and the southeastern depression zone (Zonenshain et al., 1990; Liang et al., 2020) (Figure 1a).

Figure 1

Figure 1. Geographical position and stratigraphic features of the research area. (a) Regional tectonic map of the Pre-Caspian Basin; (b) Chronostratigraphic framework of the Pre-Caspian Basin.

From the Late Devonian through the Carboniferous, a series of isolated carbonate platforms evolved along the southern margin of the Pre-Caspian Basin (Cook et al., 1997; Volozh Y. A. et al., 2003; Volozh Y. et al., 2003; Liu et al., 2003). The K Oilfield, located within the Astrakhan-Aktyubinsk intracratonic uplift zone in the southern part of the basin, constitutes one of the most prominent, largest, and most representative isolated platforms within the Devonian-Carboniferous carbonate platform archipelago of the Pre-Caspian Basin (Figure 1a) and displays a distinctive pattern of sedimentary evolution. The Carboniferous Unit 1 reservoir in the study area comprises the Visean (Livs), Serpukhovian (Serp), and Bashkirian (Bash) stages. During the Visean stage, the region was characterized by a shallow, high-energy open-marine carbonate platform, dominated by mound-shoal complex facies that were indicative of active biohermal construction and grain-dominated deposition under vigorous hydrodynamic conditions. In the Serpukhovian (Middle Carboniferous), the depositional extent of the mound-shoal complexes expanded markedly, accompanied by intermittent tuffaceous interbeds and argillaceous layers, indicating a transitional tectono-sedimentary regime along the platform-margin zone. By the Bashkirian, the areal distribution of mound-shoal complexes contracted, yet the relative abundance of high-energy grainstones—including bioclastic and oolitic grainstones—increased substantially. This shift indicates a renewed period of hydrodynamic reorganization within the platform (Figure 1b).

3 Methodology

This study focuses on the characterization of the Carboniferous Unit 1 isolated carbonate platform reservoir in the southern Pre-Caspian Basin. Samples and data were collected from 15 wells across the study area, with detailed core analysis conducted on key wells including K-3, K-4, K-5, B-1, B-2, B-3, B-4, and T-5. The primary target intervals encompass the Bash, Serp, and Lvis formations. A total of approximately 4,800 m of core and 3,500 corresponding cast thin sections were examined. High-resolution petrographic analysis was performed using Virtual Petrography view software, enabling detailed observation at magnification scales ranging from 50 μm to 4 mm. Petrographic microfacies were classified through integrated macroscopic core descriptions and microscopic thin-section observations, following the established microfacies classification framework of Flügel (2004). Reservoir pore types, including dissolution pores, intragranular pores, moldic pores, fractures, and dissolution vugs, were systematically identified at the thin-section scale. Quantitative assessment of pore type distribution was conducted using the point-counting method to compare the frequency and abundance of pore types between intra-platform and platform-margin settings.

For quantitative reservoir evaluation, (Archie, 1952; Kargarpour, 2020) porosity and permeability measurements were obtained from 4,581 core plug samples (2,679 from intra-platform and 1,902 from platform-margin settings). A subset of 353 representative samples (251 intra-platform, 102 platform-margin) was selected for mercury injection capillary pressure (MICP) analysis to characterize pore structure parameters. Conventional well log data from cored intervals were interpreted to generate continuous log-derived porosity and permeability profiles, which were calibrated against core measurements to assess data consistency. Production test data from 15 wells (7 intra-platform, 8 platform-margin) were analyzed to systematically compare static reservoir characterization results with dynamic production performance.

4 Results

4.1 Microfacies

Integrated core and thin-section analyses reveal that the Carboniferous Unit 1 reservoir in the study area was primarily deposited within a high-energy mound-shoal complex system situated above and proximal to the wave base. A consistent suite of microfacies is observed across both the platform interior and margin, dominated by grain-supported textures ranging from grainstones to packstones, with local occurrences of volcanic ash and dolomite. Based on the standard microfacies classification scheme of Flügel (2004), seven principal microfacies types are identified: skeletal grainstone (MF1), bioclastic-oolitic grainstone (MF2), oncoidal grainstone (MF3), shelly grainstone (MF4), skeletal packstone (MF5), algal-microbial boundstone (MF6), and reefal framestone (MF7). These can be broadly categorized into three groups: grainstones, packstones, and boundstones.

Of these, skeletal grainstone (MF1), shelly grainstone (MF4), skeletal packstone (MF5), algal-microbial boundstone (MF6), and reefal framestone (MF7) exhibit the most extensive spatial distribution and favorable reservoir properties (porosity and permeability), thereby constituting the dominant reservoir rock types in the study area.

4.1.1 Grainstones

The grainstones identified in this study can be categorized into four types: skeletal grainstone (MF1), bioclastic-oolitic grainstone (MF2), oncoidal grainstone (MF3), and shelly grainstone (MF4).

Skeletal grainstone (MF1) exhibits gray, grayish-white, or grayish-black coloration in core samples and predominantly occurs in thick-bedded to massive intervals. Petrographic analysis reveals that most grains are coated bioclasts, displaying micritic envelopes or complete micritization. Additional grain types include well-rounded intraclasts, peloids, and occasional ooids, all cemented by sparry calcite (Figure 2a).

Figure 2

Figure 2. Reservoir rock types of Carboniferous Unit 1 pay zone in the study area. (a) Skeletal grainstone, Foraminifera, algal lumps, and echinoderm debris developed, Well T-5, 4030.38 m; (b) bioclastic-oolitic grainstone, fractures developed, Well K-4, 3935.73 m; (c) oncoidal grainstone, Well B-2, 5270.92 m; (d) skeletal packstone, Well T-5, 4151.46 m; (e) skeletal packstone, Well T-5, 4860.86 m; (f) algal-microbial boundstone, Well T-5, 4057.14 m; (g) algal-microbial boundstone, Well T-2, 4021.20 m; (h) reefal framestone, tabulate corals are observed. Well B-3, 5195.30 m; (i) reefal framestone, colonial rugose corals are observed. Well T-2, 4195.30 m.

Bioclastic-oolitic grainstone (MF2) appears light gray to grayish-white in core. It is characterized by a high abundance of poorly sorted ooids, minor associated fossil fragments, and sparry calcite cement (Figure 2b).

Oncoidal grainstone (MF3) is macroscopically light gray. It possesses a grain-supported fabric formed by millimeter- to centimeter-scale oncoids, which are occasionally associated with ooids and fine-grained bioclasts (Figure 2c).

Shelly grainstone (MF4) is distinguished by an accumulation of gravel-sized shell fragments, primarily consisting of brachiopod and bivalve debris exceeding 2 mm in size. The interparticle space is filled with fine-grained debris, sparry calcite, and minor carbonate mud (Figure 2d).

4.1.2 Packstones

Skeletal Packstone (MF5) exhibits grayish-black coloration in the core and predominantly occurs in thick, massive beds. This microfacies is characterized by a notably higher micrite content than in the grainstones. The bioclasts are primarily composed of foraminifera, echinoderms, and algal lumps, which are indicative of relatively low-energy environments near the wave base (Figure 2e). The grain size is predominantly less than 0.5 mm.

4.1.3 Boundstones

Boundstones within the study area are subdivided into two types: algal-microbial boundstone (MF6) and reefal framestone (MF7).

Algal-microbial boundstone (MF6) displays algal or microbial binding structures. In the core, it appears grayish-white with visible dark clots. Microscopic examination reveals clots formed by the binding of micrite or mutual binding by organisms such as algae and microbes. The grain assemblage is similar to that of the akeletal packstone (MF5), consisting predominantly of lower-energy, wave-base-proximal biota including foraminifera, echinoderms, and algal lumps (Figures 2f,g).

Reefal framestone (MF7) exhibits dark brown or grayish-black coloration in the core, where coral skeletons are visible. Under the microscope, reef-building organisms such as corals and bryozoans are observed. The coral fauna is dominated by tabulate corals and colonial rugose corals (Figures 2h,i).

4.1.4 Platform interior-margin microfacies distribution

Microfacies MF1 is widely developed in both the platform interior and margin. Its thickness at the margin is relatively stable, ranging from 115.49 m to 185.58 m. In contrast, the thickness in the interior varies significantly (75.14 m–216.62 m), showing an evolutionary trend of higher development in the Lvis, a decrease in the Serp, and a peak in the Bash. MF2 exhibits a strong stage-specific distribution. At the margin, it is only sporadically developed during the Bash stage (14.96 m). In the interior, it is concentrated and extensively developed in the Bash stage (43.06 m). MF3 is overall poorly developed. It is nearly absent at the margin (thickness <0.35 m) and only minimally recorded in the interior during the Bash stage (6.15 m). MF4 occurs in both settings but dominates in different stages. Its thickness at the margin is relatively low and stable (10.38–30.74 m). In the interior, the thickness peaks in the Lvis stage (35.39 m) and subsequently decreases towards the Bash. MF5, characterized by sparry cement and deposited in a high-energy setting, shows a large and stable thickness at the margin (142.82–207.47 m). Its distribution in the interior is highly distinctive, being relatively enriched in the Lvis stage, where it reaches 618.27 m and acts as the dominant facies, before sharply decreasing to 56.62 m in the Bash. MF6 is generally more developed at the margin (thickness: 35.48–56.38 m) than in the interior (12.35–22.31 m). MF7 development shows clear facies-belt differentiation. It persists from the Lvis to Bash stages at the margin, while in the interior, it was most prosperous in the early Lvis stage (25.45 m) before gradually declining (Figure 3).

Figure 3

Figure 3. Thickness distribution of microfacies in Intea-platform faces and platform-margin facies across the Lvis, Serp, and Bash stages.

4.2 Differences in reservoir pore types

4.2.1 Reservoir pore types

Based on integrated macro- and microscopic analyses, the isolated carbonate platform in the study area exhibits a diverse array of genetic reservoir spaces. These pore spaces can be classified into three categories based on morphology and origin: secondary pores, non-selective dissolution vugs, and fractures. The primary types of pores include intergranular dissolved pores, intragranular dissolved pores, moldic pores, chamber pores, framework pores, and micropores.

Intergranular dissolved pores occur predominantly in grainstones and packstones (Figure 4a). These pores formed by leaching by meteoric freshwater and are bounded with directionally aligned bioclasts or grains with early marine rim cements, typically displaying point-to-line contacts. Their spatial distribution is generally uniform.

Figure 4

Figure 4. Reservoir pore types of Carboniferous Unit 1 pay zone. (a) Intergranular dissolution pores (IDP), skeletal grainstone, Well B-4, 4530.89 m; (b) Selective intragranular dissolved pores (WP) and Moldic pores (MO), skeletal grainstone, Well B-3, 5195.89 m; (c) Chamber pores (CP), skeletal grainstone, Well B-3, 5251.4 m; (d) Framework pores (FP), reefal framestone, Well K-4, 5193.30 m; (e) Microporosity (MP), algal-microbial boundstone, Well K-2, 4021.20 m; (f) Mottled dissolution (MD) with small vugs (VUG), skeletal packstone, Well B-4, 4096.98 m; (g) Small vugs (SV), skeletal packstone, Well K-5, 4102.97 m; (h) Microporosity (MP) and microfractures (MF), algal-microbial boundstone, Well B-3, 5451.23 m; (i) Bitumen-filled solution grooves (SG) with calcite cement, skeletal packstone, Well K-4, 4543.21 m; (j) High-angle fractures (HAF), skeletal packstone, Well K-4; (k) High-angle solution grooves (SG), skeletal packstone, Well K-4; (l) Reticulate solution grooves (SG) with brecciation, skeletal packstone, Well B-3.

Selective intragranular dissolved pores and moldic pores are well developed in sparry grainstones and bioclastic packstones, where the grains display point or non-contact relationships (Figure 4b). These pores tend to be isolated and have weak interconnections. While many open intergranular pores become occluded by cementation, the presence of micritic envelopes surrounding the grains helps to limit further diagenetic modification.

Chamber pores are mainly preserved within biogenic skeletons such as corals, foraminifera, and rudists. These pores represent residual cavities formed through selective dissolution of original skeletal chambers that were not subsequently occluded by calcite or micrite (Figure 4c). Framework pores in reef limestones consist of composite primary-to-secondary voids that remain open within the skeletal framework (Figure 4d).

Micropores are widespread in bioclastic packstones and boundstones of the study area. Although characterized by minimal diameters (generally <0.01 mm) and poor connectivity (Figure 4e), they still contribute significantly to overall reservoir storage. Most micropores formed during early diagenesis and are relatively resistant to compaction and cementation. They not only preserve residual primary porosity but also act as migration pathways for fluids during later-stage dissolution, facilitating secondary porosity development.

Non-selective dissolution vugs are irregularly distributed and exhibit marked heterogeneity, a phenomenon often referred to as mottled dissolution. As the intensity of karstification increases, there is often a gradual transition from mottled dissolution to more distinct vugs. This process is marked by patchy dissolution textures and heterogeneous fillings (Figures 4f,g).

High-angle structural fractures, dissolution fractures, and subhorizontal dissolution grooves commonly occur in association. Most dissolution grooves are filled with mixtures of carbonate mud-sand mixtures, asphalt, or volcanic ash (Figures 4h–k). Intense dissolution can lead to the formation of reticulated dissolution grooves, subhorizontal karst cavities, and brecciated fabrics (Figure 4l).

4.2.2 Differences in reservoir pore types between intra-platform and platform margins

Based on multi-scale petrographic and core-scale characterization, including detailed observations of cast thin sections and whole-core samples, the carbonate reservoirs in the study area display a pronounced predominance of secondary porosity. The dual influence of depositional-facies distribution and subsequent diagenetic modification governs the spatial architecture of reservoir voids.

Within the intra-platform reservoirs, a diverse spectrum of selectively generated pore systems—including intragranular dissolution pores, moldic pores, intergranular dissolution pores, matrix-hosted micropores, chamber pores, and framework cavities—is readily identified. Among these, intragranular and intergranular dissolution pores, moldic pores, matrix microporosity, and chamber-type voids occur predominantly within grainstone and packstone lithofacies. In contrast, framework pores are chiefly preserved within reef-limestone reservoirs associated with biogenic construction. Additionally, small-scale karstic cavities and microfracture networks are locally developed throughout the intra-platform domain, contributing to limited yet effective enhancement of fluid transmissivity. In platform-margin reservoirs, pore architectures are dominated by intragranular and intergranular dissolved pores, which are concentrated mainly within grain-supported facies such as grainstones and packstones. Simultaneously, a large number of non-selective karst caves, structural fractures, and dissolution fractures are developed in the platform margin.

A statistical evaluation of reservoir-space typologies was conducted across both intra-platform and platform-margin faces belt, utilizing a comprehensive dataset of core-derived thin-section analyses. This dataset included 2,135 samples from intra-platform settings and 1,425 from platform-margin faces belt. The quantitative results reveal significant differences in pore-type distribution between the two environments. Quantitative statistics indicate (Figure 5) that selective dissolution pores (including intragranular, intergranular, and moldic pores) account for 74.1% of the reservoir space in the intra-platform setting. In contrast, in the platform-margin reservoirs, the combined proportion of non-selective dissolution vugs and fractures reaches 39.1%, which is 4 times that in the intra-platform setting. The intra-platform domain is characterized primarily by selective dissolution-related porosity. In contrast, the platform-margin zones not only exhibit selective dissolution features but also show a much greater development of non-selective fractures, dissolution voids, and karstic cavities relative to the intra-platform reservoirs.

Figure 5

Figure 5. Histogram of pore type distribution in the platform-margin facies and intra-platform facies of Unit 1.

4.3 Differences in physical property characteristics and pore-throat structure between intra-platform and platform-margin reservoirs

4.3.1 Differences in reservoir physical properties

Based on a comprehensive analysis of petrophysical data from small-scale core samples from Carboniferous cored wells in the study area, the intra-platform reservoirs exhibit an average porosity of 8.56% and an average permeability of 3.071 mD. In contrast, the platform-margin reservoirs display an average porosity of only 3.73% and an average permeability of 2.046 mD, clearly indicating that the mean porosity and permeability values of intra-platform reservoirs are markedly superior to those of platform-margin counterparts. The porosity of intra-platform reservoirs is primarily concentrated within the range of 8%–12%, representing approximately 29.2% of the total samples; their permeability is mainly distributed between 1 and 10 mD, accounting for 36.3% of all samples. By comparison, the porosity of platform-margin reservoirs is predominantly confined to 0%–8%, accounting for 82.6% of the total samples, while their permeability is concentrated in the extremely low range of 0.01–0.1 mD, comprising 39.9% of the datasets (Figure 6).

Figure 6

Figure 6. Porosity-permeability histogram: (a) Porosity frequency distribution of intra-platform and platform-margin facies; (b) Permeability frequency distribution of intra-platform and platform-margin facies.

Based on systematic evaluation of 1,400 sets of measured core data—including 709 intra-platform and 691 platform-margin samples—the carbonate reservoirs in the study area display a pronounced facies-controlled differentiation in porosity-permeability characteristics (Figure 7). Quantitative assessment of porosity-permeability scatter plots reveals that intra-platform data points exhibit a concentrated distribution trend within high-porosity, high-permeability domains, accompanied by a strong positive correlation (Pearson’s r > 0.7), indicating that permeability increases proportionally with porosity. In contrast, platform-margin data points are primarily distributed across low-porosity, low-permeability regions and exhibit considerable scatter. A portion of the dataset displays anomalous combinations such as low-porosity-high-permeability or high-porosity-low-permeability, resulting in a significantly lower overall correlation coefficient (Pearson’s r < 0.3) (Figure 6).

Figure 7

Figure 7. Scatter diagram of porosity and permeability: (a) Porosity-permeability crossplot of intra-platform facies; (b) Porosity-permeability crossplot of platform-margin facies.

4.3.2 Differences in pore-throat structure

The Carboniferous carbonate reservoirs in the study area exhibit significant diversity in pore types and compositional complexity. This results in a distinctly non-linear relationship between porosity and permeability. Capillary-pressure curves and the corresponding pore-throat distribution profiles display clear multimodal characteristics, indicating that the intrinsic heterogeneity of the pore network cannot be fully captured by relying solely on bulk porosity-permeability parameters (Jin et al., 2018; Li et al., 2020; Mu et al., 2020).

This study systematically evaluates mercury-injection experimental data from representative reservoir intervals and the statistical analysis of pore-throat size-distribution curves. It identifies three critical thresholds for pore-throat radius: 0.1 μm, 0.5 μm, and 1 μm. These thresholds categorize the reservoir pore-throat system into four grades: micropores-throats (<0.1 μm), fine pores-throats (0.1–0.5 μm), medium pores-throats (0.5–1 μm), and coarse pores-throats (>1 μm). Through integrated coupling of petrophysical parameters, capillary-pressure curve morphology, and pore-throat distribution characteristics, a 6-fold pore-structure classification scheme was further established (Figure 8):

Figure 8

Figure 8. Pore-throat structure characteristics of platform-margin facies and intra-platform facies.

Type Ⅰ: Low-porosity, ultra-low-permeability, micro-throat type.

Type II: Medium-low porosity, low permeability, micro-to-fine throat type.

Type Ⅲ: Medium-low porosity, medium-low permeability, medium-to-coarse throat type.

Type Ⅳ: Medium-low porosity, low permeability, medium-throat type.

Type Ⅴ: Medium porosity, low permeability, coarse-throat type.

Type Ⅵ: Medium-high porosity, medium-low permeability, medium-coarse throat type.

4.3.2.1 Type Ⅰ: low-porosity, ultra-low-permeability, micro-throat type

The mercury-injection curve of this type exhibits exceptionally high median pressures and displacement values ranging from 164.06 to 3490.12 MPa. The transition segment of the curve appears gentle, suggesting relatively uniform pore-throat sorting. Micropores-micro-throats (0.01–0.1 μm) predominate, with an average radius of 0.0383 μm, forming an overall fine-skewed, single-peak distribution. Porosity values vary between 0.18% and 4.96% (average 3.33%), whereas permeability ranges from 0.001 to 1.20 mD (average 0.3305 mD). Characterized by extremely fine throats, high displacement pressure, and poor petrophysical performance despite moderate sorting, this pore-throat system is primarily developed within reefal framestone of the platform-margin facies.

4.3.2.2 Type II: medium-low porosity, low permeability, micro-to-fine throat type

The mercury-injection curve of this type displays a gently sloping trajectory with minor undulations, accompanied by relatively low displacement pressure, ranging from 48.55 to 197.27 MPa. The sorting of pore throats is moderate, with the principal peak situated in the micro-throat range (0.01–0.1 μm) and a secondary peak in the fine-throat range (0.1–0.5 μm), producing a fine-skewed, bimodal pattern. Porosity varies between 0.011% and 13.54%, with an average of 6.33%, while permeability ranges from 0.001 to 8.59 mD (average 0.8484 mD). This structure, characterized by fine-skewed throats, moderate displacement pressure, and average sorting, is commonly found in algal-microbial boundstones and skeletal grainstone of the platform-margin faces belt.

4.3.2.3 Type Ⅲ: medium-low porosity, medium-low permeability, medium-to-coarse throat type

The mercury-injection profile is distinctly inclined, featuring extremely low displacement pressure (0.51–18.25 MPa, average: 8.7158 MPa) and poor sorting. The primary peaks occur within the medium (0.5–1 μm) and coarse-throat (1–10 μm) ranges, whereas the secondary peak lies within the micro-throat interval (0.01–0.1 μm), forming a coarse-skewed, multi-peak configuration. Porosity values range from 2.3% to 18.7% (average 11.01%), and permeability extends from 0.013 to 468.25 mD (average 26.44 mD). This structure exhibits favorable petrophysical performance, coarse-skewed throats, extremely low displacement pressure, and weak sorting. It is primarily developed in algal-microbial boundstones and skeletal packstone of the platform-margin setting.

4.3.2.4 Type Ⅳ: medium-low porosity, low permeability, medium-throat type

This type’s mercury-injection curve displays comparatively low displacement pressure (1.51–124.231 MPa, average: 25.3181 MPa) and median pressure (average: 131.1571 MPa). Its mid-segment is relatively smooth, implying good pore-throat sorting. Pore-throat sizes are concentrated in the 0.5–1 μm range, forming a coarse-skewed, unimodal distribution. Porosity varies between 1.41% and 14.82% (average 10.43%), whereas permeability ranges from 0.002 to 9.32 mD (average 1.34 mD). Characterized by moderate petrophysical properties, coarse-skewed throats, low displacement pressure, and excellent sorting, this pore system is predominantly developed in shelly grainstone and skeletal packstone of the intra-platform facies.

4.3.2.5 Type Ⅴ: medium porosity, low permeability, coarse-throat type

The mercury-injection profile for this type shows low displacement pressure (1.5418–68.8790 MPa, average: 24.9331 MPa) and median pressure (average: 102.3714 MPa), with a well-defined plateau segment. Pore-throat sorting is relatively good, and pore-throat radii are primarily distributed between 1.0 and 3.0 μm, forming a coarse-skewed, unimodal pattern. Porosity values range from 6.8% to 14.52% (average 12.01%), while permeability varies from 0.26 to 9.57 mD (average 3.03 mD). This structure exhibits favorable petrophysical quality, coarse-skewed throats, extremely low displacement pressure, and excellent sorting. It is mainly developed within skeletal packstone and reefal framestone of the intra-platform setting.

4.3.2.6 Type Ⅵ: medium-high porosity, medium-low permeability, medium-coarse throat type

This mercury-injection curve indicates a low displacement pressure, ranging from 1.54 to 58.59 MPa, with an average of 25.33 MPa. The median pressure is approximately 97.91 MPa, and the curve features a prominent plateau segment. Pore-throat sorting is good, and pores-throats are concentrated between 1.0 and 10.0 μm, producing a coarse-skewed, unimodal distribution. Porosity ranges from 11.4% to 18.19% (average 14.9%), whereas permeability extends from 2.67 to 23.95 mD (average 10.78 mD). Characterized by excellent petrophysical properties, coarse-skewed throats, minimal displacement pressure, and superior sorting, this pore-throat system is chiefly developed in reefal framestone and skeletal grainstone of the intra-platform domain.

Based on the combined statistics of porosity-permeability datasets and mercury-injection measurements, the reservoirs within the platform are primarily categorized into three main types of pore-throats: Type Ⅲ (medium-low porosity, low permeability, medium-throat), Type Ⅳ (medium-low porosity, medium-low permeability, coarse-throat), and Type Ⅴ (medium-high porosity, medium-high permeability, coarse-throat). In contrast, the platform-margin reservoirs are chiefly composed of Type Ⅰ (low porosity, ultra-low permeability, micro-throat), Type Ⅱ (medium-low porosity, low permeability, micro-to-fine throat), and Type Ⅲ (medium-low porosity, medium-low permeability, medium-to-coarse throat).

5 Discussion

5.1 Depositional model

Integrated with the sedimentary evolution history of the Pre-Caspian Basin, the K oilfield was situated in an open platform environment during the Devonian. Since the Late Devonian, the basement has been uplifted by local faults, forming the embryonic form of a large, isolated carbonate platform. Accompanied by a relative sea-level rise, the platform exterior gradually transitioned to a deep-water basin. The Carboniferous period was the primary construction phase for this isolated platform, during which slope-to-deep-marine basin sedimentary systems developed around its periphery. This isolated platform is characterized by its large scale, strong hydrodynamic energy, widespread distribution of grainstones, and stable thickness. Based on facies-belt differentiation within an isolated carbonate platform, it can be subdivided into four subfacies: platform-margin reefs, platform-margin shoals, platform-interior sand flats, and platform-interior shoals.

Based on microfacies thickness distribution and sedimentary subfacies division, the depositional model of this area can be summarized as a carbonate platform evolution model dominated by sea-level changes and characterized by systematic migration of subfacies belts. In the early (Lvis) transgressive setting, microfacies MF1 and MF6 at the platform margin were stably developed, forming a shoal-reef complex subfacies that constituted a primary marginal barrier. In the platform interior, microfacies MF5 was extensively developed, establishing a depositional pattern dominated by the platform-interior sand flat subfacies with localized occurrences of the platform-interior shoal subfacies. The Serp stage represents a transitional phase. The scale of all microfacies in the interior diminished, while the scale of microfacies MF5, MF6, and MF7 in the platform margin expanded. This reflects a decline in high-energy sedimentation in the interior alongside sustained reef development on the margin. During the Bash stage, regression reached its peak. Microfacies MF1 and MF2 in the interior reached peak development, with a significant expansion of the high-energy oolitic shoals, reflecting an extremely shallow, high-energy exposed environment. Similarly, the scale of platform-margin shoals expanded, while reef-building activity on the margin diminished (Figure 9).

Figure 9

Figure 9. Depositional facies model of the study area.

5.2 Genetic mechanisms underlying differences in reservoir spaces, physical properties, and pore-throat structures between intra-platform and platform-margin settings

Integrated macro- and microscopic analyses indicate that the isolated carbonate platform in the study area exhibits a diverse array of reservoir space types (Figure 4). Systematic differences in pore-type assemblages, petrophysical parameters, and pore-throat structures are evident between intra-platform and platform-margin settings. These differences are not isolated phenomena but are governed by a unified depositional-diagenetic framework that collectively forms two distinct reservoir systems.

5.2.1 Intra-platform reservoirs: matrix-high permeability systems dominated by selective dissolution pores

Intra-platform reservoirs are characterized by selective dissolution pores (intergranular dissolved pores, intragranular dissolved pores, moldic pores) and matrix micropores as the primary reservoir spaces (Figure 5). These pore types are particularly well-developed in grainstones and packstones (MF1, MF4, MF5). The sedimentary foundation lies in the good original grain sorting and stable fabric of intra-platform sand-flat and shoal facies sediments, which created the conditions for an initial homogeneous intergranular pore system.

This favorable depositional framework directly determines their superior reservoir properties and pore-throat structures: porosity-permeability data points are concentrated in high-value regions and show a strong positive correlation (r > 0.7) (Figures 6, 7). The dominant pore-throat structures (Types IV, V, VI) are characterized by coarse throats and good sorting (Figure 8). The underlying genetic mechanism involves a relatively mild and constructive diagenetic pathway.

Primary porosity is well preserved within intra-platform reservoirs. The relatively stable water environment led to weak early cementation, thereby maximizing preservation of the primary pore network (Tucker, 2001). Subsequent selective dissolution (e.g., forming moldic pores) proceeded mainly along chemically unstable grains (e.g., aragonitic bioclasts) or along already connected intergranular pore systems, enlarging the pores without disrupting the original pore structure’s homogeneity. Matrix micropores (Figure 4e), although poorly connected, provide significant storage space and can serve as fluid migration pathways during later dissolution, promoting the uniform development of secondary porosity.

Consequently, intra-platform reservoirs form a homogeneous pore system with high synergy from pore type (selective) to physical properties (high porosity and permeability) to pore-throat structure (coarse throat, good sorting). The evolutionary theme is the preservation and uniform enlargement of the primary pore system.

5.2.2 Platform-margin reservoirs: highly heterogeneous systems with superimposed non-selective dissolution and fractures

The pore-type assemblage in platform-margin reservoirs is considerably more complex (Figure 5). In addition to selective dissolution pores, non-selective dissolution pores (Figures 4f,g), fractures, and dissolution-enhanced fracture-vug systems (Figures 4h–l) are extremely well-developed. These pore types occur in facies with inherently complex original fabrics, such as reefal framestones (MF7) and algal-microbial boundstones (MF6).

This complex pore-type assemblage directly leads to their unique petrophysical and pore-throat characteristics. Porosity-permeability data points are scattered and show a weak correlation (r < 0.3) (Figures 6, 7). The pore-throat structures are dominated by micro-to-fine throats (Types I, II) with complex multimodal distributions, alongside anomalous “low-porosity-high-permeability” data points resulting from fracture modification (Type III) (Figure 8). The genetic mechanism involves the superimposition and modification by multiple phases of intense and competitive diagenesis under high-frequency sea-level fluctuations.

Frequent exposure of platform-margin facies triggers multi-phase meteoric freshwater dissolution, forming non-selective dissolution pores. Subsequent marine transgressions are accompanied by intense and rapid cementation. Cements often clog, wholly or partially, previously formed dissolution pores and throats, leading to the generation of abundant “isolated pores” and “high-porosity-low-permeability” combinations (Moore and Wade, 2001). The framework pores in platform-margin reefal framestones (MF7) and algal-microbial boundstones (MF6) exhibit complex morphologies, uneven sizes, and poor initial pore-throat sorting. The development of fractures locally greatly enhances permeability, forming “low-porosity-high-permeability” anomalies (part of Type III structure). However, due to the significant difference in connectivity between the fracture network and the matrix pore system, the overall porosity-permeability correlation is disrupted, intensifying the heterogeneity.

5.3 Mismatch between measured physical property data and actual reservoir performance

A comparative analysis of reservoir petrology and petrophysical datasets reveals potential systematic discrepancies between laboratory-determined parameters and in situ reservoir performance in the study area. Such inconsistencies have been widely documented in analogous carbonate systems worldwide, including fractured Ordovician reservoirs of the Tarim Basin, reef-shoal carbonates of the Upper Permian Changxing Formation in the Sichuan Basin, and dolomitic reservoirs of the Khuff Formation in the Middle East, where notable deviations exist between core-derived porosity-permeability values and dynamic production behavior (Ma et al., 2012; Al-Jehani et al., 2015).

This phenomenon arises from the combined influence of several interrelated factors. On the one hand, core test outcomes are inherently constrained by sampling representativeness, scale-dependent effects, and methodological limitations (Zeng et al., 2010; Zhao et al., 2018). Particularly within fractured-vug systems, conventional core analysis captures only the matrix permeability and fails to reflect the effective seepage contribution of fracture networks. Core samples from the platform-margin zones—due to technological limitations in safe coring—are predominantly retrieved from intervals with sparse fractures, i.e., matrix-dominated sections with minimal structural conduits, leading to systematic underestimation of true permeability. Log-derived interpretations consistently indicate porosity and permeability values higher than those obtained from laboratory measurements (Figure 10), thereby verifying the pronounced effect of sampling bias on data reliability. On the other hand, the practical storage and flow behavior of carbonate reservoirs result from multifactorial coupling among pore architecture, fracture-network geometry, heterogeneity, and fluid properties (Lucia et al., 2007; Kargarpour, 2020). Laboratory testing environments cannot fully replicate in situ temperature-pressure conditions or multiphase flow dynamics, introducing unavoidable uncertainties into the measured results. Production data further corroborate this discrepancy: despite their relatively lower measured petrophysical parameters, single-well outputs in platform-margin settings are substantially higher than those of intra-platform wells (Figure 11). This observation underscores the dominant influence of preferential seepage pathways within fracture systems on actual production capacity, and once again demonstrates that laboratory-measured parameters inadequately capture the true reservoir storage potential. Hence, production potential cannot be accurately or comprehensively evaluated based solely on core-derived data.

Figure 10

Figure 10. A comparative analysis of core features and log-interpreted porosity-permeability between intra-platform and platform-margin facies belt, Carboniferous Unit 1 reservoir.

Figure 11

Figure 11. Production performance of single wells in different facies belts.

5.4 Differential karstfication controlling reservoir space differentiation

5.4.1 Facies-controlled syndiagenetic exposure dissolution governing the development of matrix dissolution pores

Numerous studies have highlighted the transformative impact of early-stage diagenetic karstification on carbonate reservoirs (Zhong et al., 2018; Xiong et al., 2019; Xie et al., 2020; Yan et al., 2025). In this study, we analyze the Carboniferous isolated carbonate platform in the Caspian Sea Basin and demonstrate that facies-controlled penecontemporaneous exposure dissolution is the primary mechanism responsible for generating matrix-dissolution pores in both intra-platform and platform-margin settings. Macro- and micro-scale examinations of cores thin section casts reveal that the main lithologies in these reservoirs include Skeletal Grainstone (MF1), Shelly Grainstone (MF4), Skeletal Packstone (MF5), Algal-Microbial Boundstone (MF6), and Reefal Framestone (MF7). These high-energy depositional facies exhibit a clear spatial association with grain-shoal and reef-mound environments. Within these areas, the reservoir spaces predominantly consist of mottled non-selective dissolution vugs as well as selectively formed intragranular and moldic pores. These features are closely linked to penecontemporaneous subaerial exposure and dissolution.

Petrographic evidence reveals that grain-shoal and mound-shoal complexes within intra-platform and platform-margin facies display high-frequency superposition of thin-bedded depositional cycles. Karstic exposure surfaces commonly develop at the tops of these cycles, where high-quality reservoir intervals preferentially occur in their middle to upper portions, producing a vertically cyclic porosity distribution. Below these exposure surfaces, early diagenetic karstification is dominated by mottled, non-selective dissolution—often superimposed with selective intragranular leaching—forming enlarged intergranular and intragranular pores, occasionally accompanied by localized brecciation near cycle tops. As depth increases below the exposure surface, the intensity of dissolution diminishes while cementation becomes progressively stronger. This shift is evident in the reduced abundance of pores and the disappearance of mottled karst textures. At the base of the cycles, the pore system is predominantly composed of micron-scale porosity with significant spatial heterogeneity (Figure 12). Collectively, these observations demonstrate that pore evolution is governed by an integrated depositional-diagenetic mechanism. The vertical variation in porosity within each depositional cycle reflects the combined influences of sedimentary microfacies and varying karst intensity, which together determine the degree and spatial pattern of matrix-dissolution development.

Figure 12

Figure 12. Exposure-related dissolution characteristics of the intra-platform facies belt in the Carboniferous Unit 1 Reservoir.

5.4.2 Superimposed coastal zone karstification controlling the development of fracture-vug systems in platform-margin zones

Although both intra-platform and platform-margin domains underwent subaerial exposure and subsequent dissolution, their reservoir architectures diverge sharply due to variations in paleotopography and karst intensity. Intra-platform reservoirs display a strongly facies-controlled distribution, with pore development predominantly governed by syndiagenetic dissolution processes, producing pervasive patchy dissolution fabrics. In contrast, the platform margin experienced far more intense karstification, as evidenced by extensive cave systems and frequent drilling-fluid loss and pipe-sticking incidents. Core investigations identify the main types of dissolution systems in platform-margin settings:

1. Dissolution pore-cave systems. These can be further categorized morphologically into intragranular dissolution pores, intergranular dissolution pores, mottled dissolution pores, and small-scale caves (less than 1 m in diameter), commonly accompanied by subordinate dissolution fractures (Figures 13a–f). These systems typically exhibit low matrix porosity.

2. Flank-margin cave systems. These refer to cavernous features exceeding 1 m in diameter, developed along platform margins and characterized by distinct cave-fill fabrics that can be observed at the core scale (Figure 13j).

Figure 13

Figure 13. Macro/micro coastal zone dissolution characteristics of platform-margin facies belt. (a) Selective dissolution vugs, skeletal grainstone, Well K-4, 4131.38 m; (b) Intergranular dissolution (ID), skeletal grainstone, Well K-2, 4563.2 m; (c) Mottled dissolution vugs (MD), skeletal packstone, Well B-3, 5352.14 m; (d) Small vugs (SV), skeletal packstone, Well K-3, 4928.71 m; (e) Solution grooves (SG) with bitumen and calcite fillings, algal-microbial boundstone, Well K-4, 4847.25 m; (f) Vugs filled with percolation silt, showing geopetal structures, skeletal grainstone, Well K-2, 4642.52 m; (g) Stage 1 coastal karst: Freshwater dissolution and cementation, skeletal packstone, Well B-3; (h) Stage 2 coastal karst: dissolution and cementation, skeletal packstone, Well B-3; (i) Stage 3 coastal karst: dissolution, skeletal packstone, Well B-4; (j) Cave-filling breccia (CFB), skeletal packstone, Well K-3.

The spatial organization of platform-margin cavities closely resembles the flank-margin cave belts formed by coastal-karst processes. High-resolution thin-section analyses further reveal multiple alternations of dissolution and cementation (Figures 13g–i). These repetitive phases of marine cementation and dissolution provide clear petrographic evidence of the significant impact of coastal karst during periods of regional platform exposure. Under the influence of sustained coastal-karst activity, early-formed dissolution pores and fracture systems gradually expanded and interconnected, developing into small cavern networks and reticulate fracture corridors. As dissolution intensity increased, brecciation developed prominently in the middle to upper portions of depositional cycles. The extension of preferential pathways for karst water significantly enhanced dissolution connectivity, ultimately resulting in the partial infilling of residual cavities with infiltrated silts and finely fragmented breccias (Figure 14).

Figure 14

Figure 14. Characteristics of coastal karstification within the platform-margin facies belt, Carboniferous Unit 1 reservoir.

5.5 Differential porosity evolution model for intra-platform and platform-margin reservoirs

The porosity evolution trajectories of intra-platform and platform-margin reservoirs display distinct stage-specific differentiation. The sequential progression of diagenetic processes primarily governs intra-platform porosity development. During the initial depositional stage, a primary pore system dominated by intergranular pores is established. During the syndiagenetic stage, infiltration of seawater and meteoric freshwater induces the precipitation of isopachous rim cements (e.g., fibrous calcite) around grain margins, thereby reducing intergranular pore volume and transforming the pore architecture into residual intergranular porosity. Subsequent sea-level fluctuations expose mound-shoal complexes and grain shoals to meteoric-water environments, triggering the selective dissolution of unstable mineral phases (e.g., aragonite and high-magnesium calcite) and the formation of secondary intragranular and moldic pores. Specifically, short-term subaerial exposure promotes selective dissolution. In contrast, prolonged exposure facilitates the formation of non-selective, patchy dissolution vugs, often accompanied by partial pore filling with dogtooth or blade calcite cements. During the burial stage, progressive overburden pressure induces mechanical compaction of shoal deposits. Supersaturated diagenetic fluids migrate through pre-existing pore channels, precipitating granular calcite that occludes intergranular voids. As burial depth increases, grain contacts progressively evolve from point contacts to line- and concavo-convex contacts. Additionally, pressure-solution phenomena emerge under the influence of slightly acidic fluids (Figure 15).

Figure 15

Figure 15. Pore evolution models for platform interior/margin facies belt.

The superimposed effects of multi-phase coastal karstification primarily control the evolution of the platform-margin pore system. During the depositional stage, the platform-margin and intra-platform zones share comparable pore-structural characteristics, both dominated by primary intergranular porosity. Submarine cementation processes generate fibrous isopachous rims around grains. At the same time, subsequent meteoric-water leaching during the syndiagenetic stage develops a matrix-dissolution pore system, establishing initial conduits for later karst-fluid migration. Selective dissolution during early diagenesis exerts only a limited effect on the platform-margin domain; coupled with early-stage compaction and cementation, portions of the pore network become infilled with sparry calcite cements. The overprinting of coastal-karst processes subsequently induces pronounced divergence in porosity evolution between the platform-margin and intra-platform zones:

1. In the initial phase of coastal karsttification, millimeter-scale dissolution pores expanded into centimeter-scale cavities.

2. During shallow burial, these forming cavities were partially filled with multi-generational calcite cements.

3. A second episode of karstification further modified and expanded the pore-cavity framework, which was subsequently sealed by burial cements.

4. The third stage of dissolution spreads along pre-existing pores and fractures, creating an interconnected fracture-cavity network.

This differential evolutionary pathway leads to significant differences in pore architecture between intra-platform and platform-margin reservoirs. Intra-platform systems are dominated by micron- to millimeter-scale matrix-dissolution pores, whereas centimeter-scale karst cavities, dissolution fractures, and compound structural-dissolution fracture networks characterize platform-margin systems.

6 Conclusion

1. Depositional facies and subsequent diagenetic modification fundamentally control the observed reservoir differentiation in the study area. Intra-platform reservoirs are characterized by homogeneous, high-quality pore systems dominated by selective dissolution in grainstone shoals. In contrast, platform-margin reservoirs feature heterogeneous fracture-vug systems developed within reef-shoal complexes, resulting from complex diagenetic overprinting under high-frequency sea-level fluctuations.

2. A discrepancy is observed between core-derived petrophysical properties, which indicate superior intra-platform reservoir quality, and production data, which demonstrate higher productivity from platform-margin reservoirs. This apparent contradiction arises because conventional core plugs are biased toward the matrix, undersampling the heterogeneous fracture-cavity networks that dominate flow in platform-margin settings. This underscores the critical influence of fracture systems on production capacity and highlights the necessity of incorporating fracture characterization into reservoir evaluation.

3. Reservoir differences are primarily controlled by karstification. Intra-platform reservoirs are shaped by syndiagenetic exposure dissolution, creating matrix-hosted porosity. Platform-margin reservoirs are further modified by coastal karst, which enhances pore connectivity through fractures and cavities, forming high-permeability flow pathways that govern productivity.

Data availability statement

The raw data supporting the conclusions of this article will be made available by the authors, without undue reservation.

Author contributions

TZ: Writing – original draft, Writing – review and editing, Conceptualization. JW: Supervision, Writing – review and editing. LZ: Methodology, Writing – review and editing. XZ: Data curation, Writing – review and editing. SW: Writing – review and editing. YC: Supervision, Writing – review and editing. JH: Resources, Writing – review and editing.

Funding

The author(s) declared that financial support was received for this work and/or its publication. This research was funded by the National Science and Technology Major Project “Technology for Enhanced Oil Recovery by Water and Gas Injection in Fracture-Pore Carbonate Reservoirs” (Grant No. 2025ZD1406405).

Conflict of interest

Author JW was employed by MangistauMunayGas B.V.

The remaining author(s) declared that this work was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

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The author(s) declared that generative AI was not used in the creation of this manuscript.

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