The study arrives at a moment when the global emissions picture remains grim. Greenhouse gas emissions climbed 2.3 percent from 2023 to a record 57.7 gigatonnes of CO2 equivalent in 2024, leaving a narrow window for staying on a trajectory consistent with the Paris Agreement’s 1.5 degree target. Against that backdrop, geological carbon storage in deep saline formations has moved from a niche idea to a central pillar of decarbonization strategies, and offshore storage in particular has attracted attention for its sealing potential, low environmental risk, and comparatively high public acceptance. Demonstration projects in Norway, the United States, Canada, Australia, Japan, and the South China Sea have proven the concept at industrial scale, from Sleipner in the North Sea to Tomakomai in Japan and Gorgon in Australia.

Egypt, with its mature petroleum provinces ringing the Gulf of Suez, has both the motive and the raw material for joining this club. The government has set greenhouse gas reduction targets for 2030 in line with the Paris Agreement, and decades of exploration drilling have produced a rich archive of seismic lines, well logs, and pressure measurements across the rift basin. The Gulf of Suez hosts thick, laterally extensive Miocene sequences with multiple sealing evaporites and well-characterized reservoirs. Previous work by some of the same authors had already assessed the structural suitability of the Belayim formation for storage; the new study takes the crucial next step by asking how injected CO2 would actually behave, dynamically, over a century.

The simulations were built in COMSOL Multiphysics using a two-phase Darcy’s law formulation for immiscible flow, coupled to phase transport to track saturation. The model represents the Hammam Faraun member as a single storage layer, roughly 50 meters thick on average, bounded below by the Belayim Evaporites and above by the South Gharib halite and anhydrite, both treated as no-flow boundaries with permeabilities as low as 10 to the power of minus 20 square meters. CO2 was injected as a supercritical fluid at formation conditions of 1.3 to 2.0 kilometers depth and about 62 degrees Celsius, with capillary pressure and relative permeability described by the Brooks-Corey model. Each simulation ran for 100 years: 25 years of injection followed by 75 years of post-injection monitoring.

Because fault behavior is one of the great uncertainties in any storage project, the team designed a three-scenario sensitivity workflow. The first scenario probed fault permeability anisotropy, testing an isotropic base case against faults whose vertical permeability was enhanced by one and then two orders of magnitude, a choice grounded in core analyses from the nearby El Morgan field showing that microfractured carbonates conduct more readily vertically, and in the observation that the maximum principal stress in the Gulf of Suez rift is vertical. The results showed that enhanced vertical fault permeability reshapes the plume along the fault planes, with CO2 spreading visibly faster and farther through faults F1, F2, and F3, even though the plume’s footprint within the reservoir itself changed little and the total mass reaching the faults remained similar across cases.

The second scenario turned to injector placement, arguably the single most consequential design decision in a faulted reservoir. Six candidate locations were tested: three future depleted oil wells, including the deviated wells D3 and D4 sharing a wellhead and the well E3, and three newly proposed injectors distributed across the upper, middle, and downthrown fault blocks. Placement proved to be a primary control on plume geometry and fault interaction. Well E3, sitting closest to fault F2, drove the fastest fault propagation, while well 1 in the upper block pushed the most CO2 into fault F1, about 5 million kilograms. Well D3, positioned moderately among the three faults, produced the least fault-crossing CO2 mass with a stable pressure buildup of 14.3 megapascals, though the authors note that its greater depth would demand higher injection pressure, making well D4 the technically favorable option overall.

The third scenario examined operational parameters. Injection rates of 5, 10, 15, and 20 kilograms per second, chosen to bracket the rates used at Sleipner and Snøhvit, showed a clear dose-response relationship: the 20 kilograms-per-second case after 25 years produced a plume larger than the 5 kilograms-per-second case after a full century. Fault F1 carried between 1.2 and 6 million kilograms of CO2 depending on rate, while F3 remained nearly inert until the highest rate pushed 3.2 million kilograms into it. A rate of 10 kilograms per second emerged as the optimum, balancing plume containment against injectivity. Variations in the Brooks-Corey pore-size distribution index, tested at values of 2 and 3 against a mean of 2.5, had comparatively minor influence on plume geometry and fault propagation, echoing earlier findings that capillary parameters of this kind play a secondary role when dissolution trapping is not explicitly modeled.

Perhaps the most reassuring result concerns pressure. Despite dramatic differences in plume size, shape, and fault interaction across all fifteen cases, wellbore pressures stabilized between roughly 13.8 and 14.8 megapascals after 100 years of simulated time. That consistency reflects the model’s high reservoir permeability of 8.88 times 10 to the power of minus 13 square meters, its lateral connectivity, and open lateral boundary conditions that let pressure dissipate efficiently away from the injector. Crucially, these pressures remain well below the regional fracture pressure threshold of about 23.3 megapascals reported for the Hammam Faraun member, providing a wide safety margin against caprock damage or fault reactivation. The authors caution, however, that this behavior is model-dependent: closed-boundary systems or rate-limited designs could produce significantly larger pressure buildups.

The study is deliberately a first step rather than a final verdict. The baseline assumes a homogeneous reservoir, an idealization that real fractured carbonates emphatically violate; heterogeneity in nature promotes preferential flow through high-permeability pathways, enhances capillary trapping in tighter zones, and can produce localized pressure anomalies. Thermal and geochemical feedbacks, including the thermoelastic stresses that cold CO2 injection can impose on the caprock, and mineral trapping reactions, were also excluded, as were explicit geomechanical couplings. The authors frame the work as a defensible hydrodynamic baseline upon which thermal, chemical, and geomechanical complexity can be layered in subsequent phases, following a simple-to-complex model hierarchy consistent with international best practice.

Even with those caveats, the implications are significant. A single well injecting at 10 kilograms per second for 25 years would sequester about 7.9 million tonnes of CO2, a figure that sits comfortably within the range of proven projects: In Salah in Algeria injected 3.8 million tonnes between 2004 and 2011, Ketzin in Germany safely injected 67,000 tonnes, Sleipner has stored roughly 16 million tonnes since 1996, and Snøhvit is expected to reach 23 million tonnes. For Egypt, the study provides the first dynamic reference case for offshore storage in the Gulf of Suez, bridging the gap between static capacity estimates and the messy, fault-steered reality of subsurface fluid flow. If the country’s decarbonization ambitions are to be met, the ancient rift that once gave up its oil may now be asked to take something back.

Subject of Research: Three-dimensional numerical simulation of supercritical CO2 injection, plume migration, and storage performance in the offshore Hammam Faraun member of the Gulf of Suez, Egypt

Article Title: CO₂ migration and storage performance in the offshore Hammam Faraun member, Gulf of Suez, Egypt

Article References: Atef, H., Singh, M., Zimmermann, G., Zang, A., & Sass, I. (2026). CO₂ migration and storage performance in the offshore Hammam Faraun member, Gulf of Suez, Egypt. Environmental Earth Sciences, 85(15), Article 388. https://doi.org/10.1007/s12665-026-13048-3

Image Credits: AI Generated

DOI: 10.1007/s12665-026-13048-3

Keywords: CO2 storage, Gulf of Suez, Hammam Faraun member, carbon capture and storage, offshore geologic sequestration, fault permeability anisotropy, injector placement, plume migration, pressure evolution, Brooks-Corey model, COMSOL simulation, Egypt decarbonization