Ученые Сколтеха выявили факторы снижения проницаемости пород при добыче арктического газа

New Data On Hydrate Gas Permeability To Boost Gas Extraction Efficiency In The Arctic September 3, 2026 In permafrost regions, subpermafrost horizons contain deposits of natural gas trapped in icelike 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 CO 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 sandclay rocks — analogues of subpermafrost gashydrate reservoirs — during injection of CO 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 hydratebearing formation, methane molecules in the hydrate lattice are replaced by CO 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 sandclay mixture saturated with methane hydrate. The samples were injected with either pure CO or a COnitrogen mixture (55% CO, 45% N), which closely mimics industrial flue gas. Gas permeability was measured at all stages: before hydrate formation, after hydrate formation, and during the methanetoCO replacement process. The results showed that injecting pure CO reduces gas permeability by an average of 54%. The reason is that residual water remaining in the rock pores participates in forming new CO hydrate crystals, which block the pathways for gas flow. With the fluegas mixture containing nitrogen, the picture is more complex: nitrogen helps liberate additional methane, and permeability actually increases at the early stage. But eventually, CO 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 CO or fluegas 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 hydratebearing rocks directly during the methanetoCO 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 CO 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 coauthor 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 CO and fluegas mixtures — our experiment allows us to distinguish and quantify them.” About Skoltech: Skoltech is a private international university (part of the VEB.RF group) in Russia, cultivating a new generation of leaders in technology, science, and business. As a factory of technologies, it conducts research in breakthrough fields and promotes technological innovation to solve critical problems that face Russia and the world. Skoltech focuses on six priority areas: life sciences, health, and agro; telecommunications, photonics, and quantum technologies; artificial intelligence; advanced materials and engineering; energy efficiency and the energy transition; and advanced studies. Established in 2011 in collaboration with the Massachusetts Institute of Technology (MIT), Skoltech was listed among the world’s top 100 young universities by the Nature Index in its both editions (2019, 2021). On Research.com, the Institute ranks as Russian university No. 2 overall and No. 1 for genetics. In the recent SCImago Institutions Rankings, Skoltech placed first nationwide for computer science. Website: https://www.skoltech.ru/.