In South Asia, a region facing rapid economic growth, immense population pressure, and high climate vulnerability, the circular economy (CE) has become a critical imperative for sustainable development. This study provides a comparative overview of the CE landscape across eight South Asian countries: Afghanistan, Bangladesh, Bhutan, India, Maldives, Nepal, Pakistan, and Sri Lanka. The analysis reveals the CE transition is nascent region-wide, though India has advanced its policy landscape through a comprehensive suite of rules and missions and Pakistan is developing a national policy. The primary focus remains on waste management, evidenced by programs like Bhutan’s ‘Zero Waste by 2030’ vision, the Maldives’ Single-Use Plastic Phase-Out Plan, and Sri Lanka’s Clean Sri Lanka Programme. While Extended Producer Responsibility (EPR) is emerging for plastics and e-waste in India, Bangladesh, Sri Lanka, and Pakistan, a significant “policy-practice gap” persists, undermined by weak enforcement and governance fragmented across priority sectors like plastics, food systems, and textiles. Most major CE initiatives are catalyzed by international development partners, with regional programs playing a key role in funding innovation. Finally, while the informal sector is the backbone of material recovery, ensuring a just transition that improves working conditions and secures livelihoods remains a critical challenge. The absence of a cohesive regional framework limits collaboration. Scaling the circular economy in South Asia requires integrated national strategies, prioritizing a just transition for the informal sector, and establishing a regional platform for policy harmonization to create self-sustaining system through multi-sectoral involvement, including the business sector.

The analysis of geological and petrophysical properties is fundamental for evaluating the heterogeneous and complex nature of carbonate reservoirs, such as those of the Brazilian subsalt. Although porosity and permeability are routinely quantified at the core scale, the relationship between pore geometry and these properties remains complex and highly variable in carbonate systems. This study investigates how pore-scale geometric attributes derived from thin sections relate to porosity and permeability measured in corresponding core plugs from the Barra Velha Formation, Santos Basin. Digital image analysis (DIA) was applied to 355 blue-epoxy–impregnated thin sections to quantify total optical porosity (TOP) and pore geometry parameters, including aspect ratio, gamma (circularity), pore structure complexity (perimeter over area [PoA]), and dominant pore size (DomSize). Facies (F1–F5) and pore types were identified qualitatively to support geological interpretation, and routine core analyses were obtained from 304 core-plug samples. Permeability was initially estimated using the Kozeny equation and subsequently refined through facies-specific multivariate linear regression (MLR) models incorporating TOP and geometric parameters. The results indicate that facies F1, F2, and F4 exhibit higher porosity and permeability associated with interparticle and vuggy pore systems, whereas facies F3 and F5 display lower permeability linked to intraparticle and moldic pores and stronger diagenetic modification. Silicification locally reduces porosity, while, in some cases, increasing DomSize through selective dissolution. Overall, permeability is primarily controlled by DomSize and PoA. Facies-specific MLR models significantly outperform Kozeny-based estimates, highlighting the potential of DIA as a cost-effective tool for core-scale reservoir characterization in complex carbonate reservoirs.

With the gradual depletion of oil and gas resources in shallower strata (6000 m) is becoming inevitable. Recent 10,000-m drilling projects in China highlight the petroleum accumulation and enrichment model and reserve potential in ultradeep strata of cratonic basins. This study systematically summarizes 10,000-m deep petroleum geology model, based on recent research progress and exploration discoveries. The lower limit of liquid petroleum preservation depth in basins with low-geothermal gradient (e.g., Tarim Basin with 19.6°C/km) can reach 9000 m, breaking through conventional understanding of a 6000-m depth limit. Different hydrocarbon compounds exhibit distinct thermal stability in that saturated hydrocarbons are more resistant to cracking than aromatic hydrocarbons, whereas diamondoids accumulate during oil cracking and serve as reliable maturity markers. Recent ultradeep drilling confirms this expanded exploration potential. The research reveals preservation mechanisms for paleo oil pools (250 Ma hydrocarbon accumulation age) and gas pools (100 Ma hydrocarbon accumulation age), and thus redefines the ultimate lifespan of oil/gas pools. Experimental simulations have shown that caves and pores are influenced by only lithostatic pressure and can remain even at depths of 75,000 m, carbonate reservoirs therefore have no firmed depth limit. The flow and migration of hydrocarbon fluids in ultradeep strata differ significantly from the buoyancy-driven models in middle to shallow strata. These processes do not fully follow the buoyancy differentiation law and feature multioil-water interfaces in fracture-cavity type reservoirs. Flow and occurrence model of hydrocarbon fluids in heterogeneous reservoirs has thus been established, introducing the concept of large-area stratified cavity-fracture type bead-like pools without unified oil-water contacts. Ultradeep petroleum exploration has revealed oil fields with nearly 1000-m-high oil columns and a series of wells producing up to 1000 metric tons of oil per day (7330 BOPD), challenging traditional theories of petroleum accumulation that focus on high points of traps. These findings provide theoretical support for significant discoveries and strategic changes in ultradeep petroleum exploration and expand petroleum exploration space up to 10,000 m deep.

Understanding reservoir fluid overpressure evolution is vital for characterizing petroleum accumulation and preservation in deeply buried reservoirs. This study integrates petrography, fluid inclusion (FI) microthermometry, Raman spectroscopy, thermodynamics, and basin modeling to constrain the diagenetic fluid history of the Ediacaran Dengying Formation, Sichuan Basin, South China. Petrographic observations reveal a complex cementation sequence from early calcite 1 and dolomite 1 to late-stage quartz and fluorite. In situ U-Pb dating of FI-hosted dolomite 2 (232.9 ± 7.4 Ma) identifies a 60-bar overpressure buildup during rapid late Permian burial. Intense peak overpressure (360–690 bar) occurred during quartz and fluorite precipitation under the Yanshanian compression regime, supported by fluorite dating of 106.8 ± 7.5 Ma. At trapping temperatures exceeding 200°C, thermochemical sulfate reduction (TSR) and oil cracking were responsible for fluid expansion and intense overpressure buildup. Since the Paleogene, major tectonic uplift and fluid drainage have caused overpressure to decrease from 367 to 0 bar. This integrated microscale–macroscale workflow links tectonic events to pore-fluid processes with global universality. The Triassic rifting triggered rapid source rock maturation and oil cracking, a mechanism that is highly similar to that of the Aquitaine Basin, France. Commonalities in methane reserves and H2S content between these basins suggest an intrinsic coupling between rapid maturation and TSR. Furthermore, the significant pressure attenuation observed implies that hydrocarbons may have remigrated to adjacent undiscovered reservoirs rather than simply leaking, offering a strategic new direction for deep-seated petroleum exploration deployment.

Hydrocarbon production from the Mississippian Caney Shale, Ardmore Basin, is highly influenced by the heterogeneous rock physical properties. This research aims to establish a petrographic model to better understand the potential diagenetic pathways and evolution of bulk physical properties among different lithologies in the Caney Shale. The lithological variation, primary grain assemblages, diagenetic features, and evolution of bulk petrophysical properties were investigated based on detailed petrographic, geochemical, and petrophysical analysis of 93 core plug samples. The results suggest that the Caney Shale comprises five major lithologies: massive argillaceous mudstone, planar-laminated argillaceous mudstone, planar-laminated siliceous mudstone, massive calcareous mudstone, and massive to wavy-laminated wackestone and packstone. The primary grains in massive argillaceous mudstone are extremely terrigenous-rich (82 to 95 vol. %), whereas variable content of biogenic carbonate or silica allochems can be observed from the other four lithologies. The variations of grain components (extrabasinal versus intrabasinal) among different lithologies are likely caused by periodic sea level changes and the relative distance to the provenance. Due to this variation in grain assemblage composition, the sample suite displays a corresponding evolution in diagenetic variety and petrophysical properties. Massive argillaceous mudstone dominated by extrabasinal grains underwent intense mechanical compaction, resulting in low bulk porosity and permeability, whereas samples from other lithologies with greater amounts of intrabasinal grains underwent considerable cementation, resulting in variable but overall higher porosity and permeability. This study provides an example of new perspectives for linking micrometer-scale petrographic features to the evolution of bulk physical properties in shale.

With the gradual depletion of oil and gas resources in shallower strata (6000 m) is becoming inevitable. Recent 10,000-m drilling projects in China highlight the petroleum accumulation and enrichment model and reserve potential in ultradeep strata of cratonic basins. This study systematically summarizes 10,000-m deep petroleum geology model, based on recent research progress and exploration discoveries. The lower limit of liquid petroleum preservation depth in basins with low-geothermal gradient (e.g., Tarim Basin with 19.6°C/km) can reach 9000 m, breaking through conventional understanding of a 6000-m depth limit. Different hydrocarbon compounds exhibit distinct thermal stability in that saturated hydrocarbons are more resistant to cracking than aromatic hydrocarbons, whereas diamondoids accumulate during oil cracking and serve as reliable maturity markers. Recent ultradeep drilling confirms this expanded exploration potential. The research reveals preservation mechanisms for paleo oil pools (250 Ma hydrocarbon accumulation age) and gas pools (100 Ma hydrocarbon accumulation age), and thus redefines the ultimate lifespan of oil/gas pools. Experimental simulations have shown that caves and pores are influenced by only lithostatic pressure and can remain even at depths of 75,000 m, carbonate reservoirs therefore have no firmed depth limit. The flow and migration of hydrocarbon fluids in ultradeep strata differ significantly from the buoyancy-driven models in middle to shallow strata. These processes do not fully follow the buoyancy differentiation law and feature multioil-water interfaces in fracture-cavity type reservoirs. Flow and occurrence model of hydrocarbon fluids in heterogeneous reservoirs has thus been established, introducing the concept of large-area stratified cavity-fracture type bead-like pools without unified oil-water contacts. Ultradeep petroleum exploration has revealed oil fields with nearly 1000-m-high oil columns and a series of wells producing up to 1000 metric tons of oil per day (7330 BOPD), challenging traditional theories of petroleum accumulation that focus on high points of traps. These findings provide theoretical support for significant discoveries and strategic changes in ultradeep petroleum exploration and expand petroleum exploration space up to 10,000 m deep.

With the gradual depletion of oil and gas resources in shallower strata (6000 m) is becoming inevitable. Recent 10,000-m drilling projects in China highlight the petroleum accumulation and enrichment model and reserve potential in ultradeep strata of cratonic basins. This study systematically summarizes 10,000-m deep petroleum geology model, based on recent research progress and exploration discoveries. The lower limit of liquid petroleum preservation depth in basins with low-geothermal gradient (e.g., Tarim Basin with 19.6°C/km) can reach 9000 m, breaking through conventional understanding of a 6000-m depth limit. Different hydrocarbon compounds exhibit distinct thermal stability in that saturated hydrocarbons are more resistant to cracking than aromatic hydrocarbons, whereas diamondoids accumulate during oil cracking and serve as reliable maturity markers. Recent ultradeep drilling confirms this expanded exploration potential. The research reveals preservation mechanisms for paleo oil pools (250 Ma hydrocarbon accumulation age) and gas pools (100 Ma hydrocarbon accumulation age), and thus redefines the ultimate lifespan of oil/gas pools. Experimental simulations have shown that caves and pores are influenced by only lithostatic pressure and can remain even at depths of 75,000 m, carbonate reservoirs therefore have no firmed depth limit. The flow and migration of hydrocarbon fluids in ultradeep strata differ significantly from the buoyancy-driven models in middle to shallow strata. These processes do not fully follow the buoyancy differentiation law and feature multioil-water interfaces in fracture-cavity type reservoirs. Flow and occurrence model of hydrocarbon fluids in heterogeneous reservoirs has thus been established, introducing the concept of large-area stratified cavity-fracture type bead-like pools without unified oil-water contacts. Ultradeep petroleum exploration has revealed oil fields with nearly 1000-m-high oil columns and a series of wells producing up to 1000 metric tons of oil per day (7330 BOPD), challenging traditional theories of petroleum accumulation that focus on high points of traps. These findings provide theoretical support for significant discoveries and strategic changes in ultradeep petroleum exploration and expand petroleum exploration space up to 10,000 m deep.

The analysis of geological and petrophysical properties is fundamental for evaluating the heterogeneous and complex nature of carbonate reservoirs, such as those of the Brazilian subsalt. Although porosity and permeability are routinely quantified at the core scale, the relationship between pore geometry and these properties remains complex and highly variable in carbonate systems. This study investigates how pore-scale geometric attributes derived from thin sections relate to porosity and permeability measured in corresponding core plugs from the Barra Velha Formation, Santos Basin. Digital image analysis (DIA) was applied to 355 blue-epoxy–impregnated thin sections to quantify total optical porosity (TOP) and pore geometry parameters, including aspect ratio, gamma (circularity), pore structure complexity (perimeter over area [PoA]), and dominant pore size (DomSize). Facies (F1–F5) and pore types were identified qualitatively to support geological interpretation, and routine core analyses were obtained from 304 core-plug samples. Permeability was initially estimated using the Kozeny equation and subsequently refined through facies-specific multivariate linear regression (MLR) models incorporating TOP and geometric parameters. The results indicate that facies F1, F2, and F4 exhibit higher porosity and permeability associated with interparticle and vuggy pore systems, whereas facies F3 and F5 display lower permeability linked to intraparticle and moldic pores and stronger diagenetic modification. Silicification locally reduces porosity, while, in some cases, increasing DomSize through selective dissolution. Overall, permeability is primarily controlled by DomSize and PoA. Facies-specific MLR models significantly outperform Kozeny-based estimates, highlighting the potential of DIA as a cost-effective tool for core-scale reservoir characterization in complex carbonate reservoirs.

The analysis of geological and petrophysical properties is fundamental for evaluating the heterogeneous and complex nature of carbonate reservoirs, such as those of the Brazilian subsalt. Although porosity and permeability are routinely quantified at the core scale, the relationship between pore geometry and these properties remains complex and highly variable in carbonate systems. This study investigates how pore-scale geometric attributes derived from thin sections relate to porosity and permeability measured in corresponding core plugs from the Barra Velha Formation, Santos Basin. Digital image analysis (DIA) was applied to 355 blue-epoxy–impregnated thin sections to quantify total optical porosity (TOP) and pore geometry parameters, including aspect ratio, gamma (circularity), pore structure complexity (perimeter over area [PoA]), and dominant pore size (DomSize). Facies (F1–F5) and pore types were identified qualitatively to support geological interpretation, and routine core analyses were obtained from 304 core-plug samples. Permeability was initially estimated using the Kozeny equation and subsequently refined through facies-specific multivariate linear regression (MLR) models incorporating TOP and geometric parameters. The results indicate that facies F1, F2, and F4 exhibit higher porosity and permeability associated with interparticle and vuggy pore systems, whereas facies F3 and F5 display lower permeability linked to intraparticle and moldic pores and stronger diagenetic modification. Silicification locally reduces porosity, while, in some cases, increasing DomSize through selective dissolution. Overall, permeability is primarily controlled by DomSize and PoA. Facies-specific MLR models significantly outperform Kozeny-based estimates, highlighting the potential of DIA as a cost-effective tool for core-scale reservoir characterization in complex carbonate reservoirs.