Search Results (4)

With the continuous growth of global energy demand, greenhouse gas emissions are also rising, leading to serious challenges posed by climate change. Carbon Capture, Utilization, and Storage (CCUS) technology is considered one of the key pathways to mitigate climate change. Among the CCUS technologies, CO₂ storage in offshore saline aquifers has gained significant attention in recent years. This paper conducts an in-depth analysis of the Sleipner and Snøhvit projects in Norway and the Tomakomai project in Japan, exploring key issues related to the application, geological characteristics, injection strategies, monitoring systems, and simulation methods of CO₂ storage in offshore saline aquifers. This study finds that CO₂ storage in offshore saline aquifers has high safety and storage potential but faces several challenges in practical applications, such as geological reservoir characteristics, technological innovation, operational costs, and social acceptance. Therefore, it is necessary to further strengthen technological innovation and policy support to promote the development and application of CO₂ storage in offshore saline aquifers. This study provides valuable experiences and insights for similar projects worldwide, contributing to the sustainable development of CO₂ storage in offshore saline aquifers and making a greater contribution to achieving global net-zero emission targets. Full article

To achieve carbon neutrality in China’s fossil energy sector, saline aquifer CO₂ geological storage has become a critical strategy. As research into carbon reduction and storage potential evaluation advances across various geological scales, the need arises for consolidating key CO₂ storage cases and establishing a standardized classification system and evaluation methodology. This paper provides a comprehensive review of notable CO₂ storage projects in saline aquifers, covering aspects such as project overviews, structural and reservoir characteristics, caprock integrity, and seismic monitoring protocols. Drawing on insights from mineral and oil and gas exploration, as well as international methods, this paper outlines the stages and potential levels of saline aquifer storage in China. It proposes an evaluation framework with formulas and reference values for key coefficients. The study includes successful global projects, such as Sleipner and Snøhvit in Norway, In Salah in Algeria, and Shenhua in China’s Ordos Basin, which provide valuable insights for long-term carbon capture and storage (CCS). By examining geological characteristics, injection, and monitoring protocols in these projects, this paper analyzes how geological features impact CO₂ storage outcomes. For example, the Sleipner project’s success is linked to its straightforward structure, favorable reservoir properties, and stable caprock, while Snøhvit illustrates diverse structural suitability, and In Salah demonstrates the influence of fractures on storage efficacy. CO₂ storage activities are segmented into four stages—survey, investigation, exploration, and injection—and are further categorized by storage potential: geological, technical, techno-economic, and engineering capacities. This study also presents evaluation levels (prediction, control, technically recoverable, and engineering) that support effective reservoir selection, potential classification, and calculations considering factors like reservoir stability and sealing efficacy. Depending on application needs, volumetric or mechanistic methods are recommended, with precise determination of geological, displacement, and cost coefficients. For China, a dynamic evaluation mechanism characterized by multi-scale, tiered approaches and increasing precision over time is essential for robust storage potential assessment. The levels and methods outlined here serve as a scientific foundation for regional and stage-based comparisons, guiding engineering approvals and underground space management. To align with practical engineering demands, ongoing innovation through laboratory experiments, simulations, and field practice is crucial, supporting continual refinement of formulas and key parameter determinations. Full article

Gas chimneys are one of the most intriguing manifestations of the focused fluid flows in sedimentary basins. To predict natural and human-induced fluid leakage, it is essential to understand the mechanism of how fluid flow localizes into conductive chimneys and the chimney dynamics. This work predicts conditions and parameters for chimney formation in two fields in the SW Barents Sea, the Tornerose field and the Snøhvit field in the Hammerfest Basin. The work is based on two types of models, basin modeling and hydro-mechanical modeling of chimney formation. Multi-layer basin models were used to produce the initial conditions for the hydro-mechanical modeling of the relatively fast chimneys propagation process. Using hydro-mechanical models, we determined the thermal, structural, and petrophysical features of the gas chimney formation for the Tornerose field and the Snøhvit field. Our hydro-mechanical model treats the propagation of chimneys through lithological boundaries with strong contrasts. The model reproduces chimneys identified by seismic imaging without pre-defining their locations or geometry. The chimney locations were determined by the steepness of the interface between the reservoir and the caprock, the reservoir thickness, and the compaction length of the strata. We demonstrate that chimneys are highly-permeable leakage pathways. The width and propagation speed of a single chimney strongly depends on the viscosity and permeability of the rock. For the chimneys of the Snøhvit field, the predicted time of formation is about 13 to 40 years for an about 2 km high chimney. Full article

Hydrocarbon prospectivity in the Greater Barents Sea remains enigmatic as gas discoveries have dominated over oil in the past three decades. Numerous hydrocarbon-related fluid flow anomalies in the area indicate leakage and redistribution of petroleum in the subsurface. Many questions remain unanswered regarding the geological driving factors for leakage from the reservoirs and the response of deep petroleum reservoirs to the Cenozoic exhumation and the Pliocene-Pleistocene glaciations. Based on 2D and 3D seismic data interpretation, we constructed a basin-scale regional 3D petroleum systems model for the Hammerfest Basin (1 km × 1 km grid spacing). A higher resolution model (200 m × 200 m grid spacing) for the Snøhvit and Albatross fields was then nested in the regional model to further our understanding of the subsurface development over geological time. We tested the sensitivity of the modeled petroleum leakage by including and varying fault properties as a function of burial and erosion, namely fault capillary entry pressures and permeability during glacial cycles. In this study, we find that the greatest mass lost from the Jurassic reservoirs occurs during ice unloading, which accounts for a 60%–80% reduction of initial accumulated mass in the reservoirs. Subsequent leakage events show a stepwise decrease of 7%–25% of the remaining mass from the reservoirs. The latest episode of hydrocarbon leakage occurred following the Last Glacial Maximum (LGM) when differential loading of Quaternary strata resulted in reservoir tilt and spill. The first modeled hydrocarbon leakage event coincides with a major fluid venting episode at the time of a major Upper Regional angular Unconformity (URU, ~0.8 Ma), evidenced by an abundance of pockmarks at this stratigraphic interval. Our modelling results show that leakage along the faults bounding the reservoir is the dominant mechanism for hydrocarbon leakage and is in agreement with observed shallow gas leakage indicators of gas chimneys, pockmarks and fluid escape pipes. We propose a conceptual model where leaked thermogenic gases from the reservoir were also locked in gas hydrate deposits beneath the base of the glacier during glaciations of the Hammerfest Basin and decomposed rapidly during subsequent deglaciation, forming pockmarks and fluid escape pipes. This is the first study to our knowledge to integrate petroleum systems modelling with seismic mapping of hydrocarbon leakage indicators for a holistic numerical model of the subsurface geology, thus closing the gap between the seismic mapping of fluid flow events and the geological history of the area. Full article