In permafrost regions, sub‑permafrost horizons contain deposits of natural gas trapped in ice‑like crystals known as gas hydrates. To extract this gas, carbon dioxide can be injected into the reservoir, displacing methane from the hydrate crystal lattice while itself remaining trapped in hydrate form. However, during this replacement process, new CO₂ hydrate crystals also form in the rock, which can clog pore channels. As a result, the rock’s ability to transmit gas decreases, directly affecting methane recovery efficiency.
Scientists at Skoltech (part of the VEB.RF Group), together with a colleague from the Ulsan National Institute of Science and Technology (UNIST) in South Korea, have conducted an experimental study on how gas permeability changes in sand‑clay rocks — analogues of sub‑permafrost gas‑hydrate reservoirs — during injection of CO₂ and flue gases under conditions typical of Arctic hydrate reservoirs. The work is published in the journal Natural Gas Industry B. The findings have direct practical implications for planning commercial gas production from hydrate deposits in the Arctic.
When carbon dioxide is injected into a hydrate‑bearing formation, methane molecules in the hydrate lattice are replaced by CO₂ molecules. This frees the methane for extraction while safely sequestering the carbon dioxide in hydrate form. This approach addresses two challenges at once — gas production and greenhouse gas disposal — without compromising formation stability.
The researchers recreated Arctic reservoir conditions in the laboratory, simulating formations located beneath the permafrost layer. They worked at a temperature of +1 °C and used samples composed of a sand‑clay mixture saturated with methane hydrate. The samples were injected with either pure CO₂ or a CO₂‑nitrogen mixture (55% CO₂, 45% N₂), which closely mimics industrial flue gas. Gas permeability was measured at all stages: before hydrate formation, after hydrate formation, and during the methane‑to‑CO₂ replacement process.
The results showed that injecting pure CO₂ reduces gas permeability by an average of 54%. The reason is that residual water remaining in the rock pores participates in forming new CO₂ hydrate crystals, which block the pathways for gas flow. With the flue‑gas mixture containing nitrogen, the picture is more complex: nitrogen helps liberate additional methane, and permeability actually increases at the early stage. But eventually, CO₂ hydrate formation still drives it down. In samples with high water content, the permeability drop reached as much as 79%.
These data are crucial for planning commercial gas production from hydrate accumulations in the Arctic. If the formation contains a large amount of residual water, permeability after CO₂ or flue‑gas injection will decline more severely. If the formation is relatively dry, the decline will be smaller. The higher the initial hydrate saturation in the rock, the harder it is to predict how permeability will change. Accounting for these factors will allow more accurate forecasting of recoverable gas volumes and help select the optimal injection regime.
“We have experimentally demonstrated how gas permeability changes in hydrate‑bearing rocks directly during the methane‑to‑CO₂ replacement process,” commented Leading Research Scientist Evgeny Chuvilin from the Skoltech Petroleum Center, the lead author and principal investigator of the study. “This effect is not obvious — on the one hand, methane is released and permeability should increase, but on the other, secondary CO₂ hydrate formation reduces it. We have quantified the balance between these competing processes. Now we have data that can be fed into models for developing hydrate fields in the Arctic.”
“From a practical standpoint, our study gives engineers criteria for choosing the optimal injection strategy,” added Maxim Zhmaev, an engineer at the Skoltech Petroleum Center and a graduate of Skoltech’s PhD program in Petroleum Engineering, a co‑author of the paper. “If we are working with a formation rich in residual water, we need to anticipate a significant permeability drop — and build that into our calculations. If the formation is relatively dry, the decline will be less pronounced. The relationships differ for pure CO₂ and flue‑gas mixtures — our experiment allows us to distinguish and quantify them.”
