South Africa’s 150-Gigatonne CO2 Storage Prize Lies Offshore, Review Finds

South Africa emitted 401.89 million tonnes of carbon dioxide from fossil fuels and industry in 2023, and a new systematic review concludes that the country’s best hope for burying those emissions lies almost entirely beneath the sea. The review, published in Discover Energy, synthesizes decades of published and grey literature on the nation’s major sedimentary basins and finds a theoretical geologic storage capacity of roughly 150 gigatonnes, with a practical potential of at least 100 gigatonnes. Nearly 98 percent of that capacity sits in offshore deep saline aquifers, distributed across the Orange, Outeniqua, and Durban/Zululand basins, with only minor onshore potential.

The review is a synthesis rather than a new basin assessment. Their goal was to fill a gap they identify in existing South African carbon capture and storage research: most prior studies emphasize technical potential in isolation, without ranking basins by suitability or integrating socio-economic and infrastructural constraints.

The capacity figures trace back to an initial national assessment commissioned by the Department of Minerals and Petroleum Resources and published in 2004. Of the 150 gigatonnes theoretical total, the review reports the Orange Basin holds an estimated 56 gigatonnes, the Outeniqua Basin 48 gigatonnes, and the Durban/Zululand basin 42 gigatonnes. The Council for Geoscience’s national storage atlas and subsequent screening work identified the Bredasdorp Basin, a sub-basin of the Outeniqua system, as meeting the highest class of suitability criteria, making it South Africa’s most promising candidate for carbon dioxide storage. The Outeniqua Basin, including the Bredasdorp and Pletmos sub-basins, is currently regarded as the most viable storage site because of existing infrastructure and robust geological datasets.

That promise rests on a substantial body of recent site-specific work. A 2020 geomechanical study of a depleted gas field in the Bredasdorp Basin, using data from three producing and twelve exploratory wells, found a predominantly normal stress regime and recommended a maximum sustainable injection pressure below 25 megapascals to keep faults stable. Static modelling of the depleted Charis reservoir, with porosity of 13.92 percent and permeability between 100 and 560 millidarcies, yielded capacity estimates of 1.62 megatonnes for a virgin oilfield and 0.71 megatonnes for a virgin aquifer, and showed that depleting the reservoir to bubble-point pressure more than doubled storage capacity compared with depletion at initial pressure.

Machine learning is also entering the picture. One study applied XG-Boost and artificial neural network algorithms calibrated with core data to improve porosity and permeability predictions in the basin’s siliciclastic reservoirs, producing more accurate estimates than traditional empirical approaches and defining a stable injection window bounded by a lithostatic pressure of 18.9 pounds per gallon equivalent, pore pressure of 8.5, and a fracture gradient of 12. Yet fault-related containment risk remains the most significant challenge in the Bredasdorp Basin. A three-dimensional seismic-based slip-tendency analysis of the F-O gas field found that faults near injection wells have higher slip potential because of their orientation relative to the regional stress field, with increasing pore pressure the primary factor influencing slip potential. In the Pletmos sub-basin, however, juxtaposition analysis and Shale Gouge Ratio algorithms demonstrated that several faults possess moderate to high sealing capacity, enhancing containment feasibility.

Other basins fare less well in the synthesis. The Algoa Basin, an onshore Mesozoic half-graben north of Port Elizabeth, offers a theoretical capacity of around 404 million tonnes in deep saline aquifers, with the most prospective reservoirs in the fluvial sandstones of the Kirkwood and Sundays River formations. But reservoir quality degrades sharply with depth: porosities up to 27 percent and permeabilities up to 48 millidarcies at roughly 800 metres fall away below 2500 metres as clay content rises, and porosity in the Sundays River Formation drops from about 23 percent at 800 metres to about 11 percent at 1800 metres. Seismic resolution is insufficient to delineate reservoirs and seals thinner than 30 metres, one of seven candidate sites has been excluded as a groundwater protection zone, and injectivity remains unproven.

The Zululand Basin illustrates how widely estimates can diverge when data are sparse. Published assessments of its storage potential range from 150 gigatonnes down to 460 megatonnes, a spread the review attributes to significant geological uncertainty and methodological differences. Aptian-aged offshore sandstones are considered the primary target, with average porosity around 20 percent but permeabilities typically below 1 millidarcy, while a recent three-dimensional static model of an onshore sandstone formation reported permeabilities of 100 to 1000 millidarcies and a site-specific capacity of about 0.54 megatonnes. Much of the existing core material is altered or weathered, seal integrity above 800 metres is poorly constrained, and current capacity estimates remain largely probabilistic. The offshore Durban Basin, a sheared-rift basin of about 10,000 square kilometres, has yielded four dry wildcat wells and no confirmed reservoirs; capacity estimates there range from about 5 gigatonnes to a probabilistic 643 to 2196 megatonnes, all highly uncertain. The Karoo Basin, the only major onshore option, offers limited potential because of poor porosity and permeability in the Ecca Group, and its carbonaceous shales and siltstones have been found to be overmature, limiting carbon dioxide adsorption affinity.

Against these geological constraints stand institutional and policy foundations that the review describes as strong. Carbon capture and storage was designated a flagship program in the 2011 National Climate Change Response White Paper, the CCS Road Map received cabinet approval in May 2013, and the technology was incorporated into the 2030 National Development Plan. However, there is no dedicated CCS legislation; development is currently governed through general environmental and tax law, including the National Environmental Management Act, the Climate Change Act, and a carbon tax regime whose second phase begins in 2026, reducing tax-free allowances and raising rates to a projected 462 rand per tonne of carbon dioxide equivalent by 2030.

Cost remains the dominant barrier. The review notes that large-scale CCUS demonstrations have exceeded one billion US dollars, and first-of-a-kind plants have exceeded seven billion dollars, while depleted reservoirs, unlike enhanced oil recovery, provide limited economic return, making sequestration dependent on carbon pricing or government incentives. Additional obstacles include insufficient datasets for site characterization, limited domestic research capacity, a shortage of skilled professionals, lengthy approval periods, the absence of an operational carbon trading market and storage credits, and complex ownership transfers of depleted hydrocarbon fields. Some environmental non-governmental organizations oppose CCS as prolonging fossil fuel dependence, and governance is complicated by overlapping jurisdictional controls, diverse land rights, and protected areas including national parks and UNESCO World Heritage Sites.

The review’s conclusion is measured: South Africa’s basins hold significant theoretical potential, but effective storage capacity remains poorly constrained by limited data, and extensive site-specific research is required before large-scale deployment becomes viable. The authors call for multidisciplinary investigations spanning geophysics, petrophysics, geomechanics, geochemistry, sedimentology and dynamic modelling, along with new drilling for fresh core, modern seismic surveys, and engagement of policymakers, societal opinion shapers and oil industry professionals to build stakeholder support. Depleted gas fields in the Bredasdorp Basin, better documented with proven seals that have retained hydrocarbons for millennia, are identified as more practical candidates for early deployment than the vast but poorly characterized saline aquifers. A hub-and-cluster model similar to Europe’s Northern Lights and Porthos projects is proposed to reduce costs through shared transport infrastructure, focusing on high-emission zones in Mpumalanga and KwaZulu-Natal, as the country pursues its commitment to net-zero emissions by 2050.

Subject of Research: Geologic carbon dioxide storage potential in South Africa's major sedimentary basins

Article Title: A review and evaluation of geologic CO2 storage potential in major South African Sedimentary Basins, with emphasis on opportunities, challenges, and future perspectives for climate change mitigation

Article References: Olayinka, Y. A., Afolayan, B., Eruteya, O. E., & Opuwari, M. (2026). A review and evaluation of geologic CO2 storage potential in major South African Sedimentary Basins, with emphasis on opportunities, challenges, and future perspectives for climate change mitigation. Discover Energy, 6(1), Article 88. https://doi.org/10.1007/s43937-026-00194-9

Image Credits: AI Generated

DOI: 10.1007/s43937-026-00194-9

Keywords: carbon capture and storage, South Africa, CO2 storage capacity, Bredasdorp Basin, Orange Basin, saline aquifers, depleted gas fields, geomechanics, Karoo Basin, CCUS policy, carbon tax, offshore basins