Deep in permafrost regions lie vast deposits of natural gas trapped inside ice-like crystals known as gas hydrates. To extract this gas, carbon dioxide can be pumped into the reservoir: it displaces the methane from the hydrate lattice while remaining safely locked away in hydrate form. Yet this swap comes with a catch. As the replacement happens, brand-new CO₂ hydrate crystals form within the rock, clogging up pore channels and choking off gas flow.
To figure out exactly how this impacts permeability, the team recreated Arctic reservoir conditions in the lab, holding samples at a chilly +1 °C and injecting either pure CO₂ or a CO₂–nitrogen mixture that closely mimics industrial flue gas.
The results showed that injecting pure CO₂ drops gas permeability by an average of 54%. Leftover water trapped in the rock's pores reacts to form these secondary CO₂ hydrates, effectively blocking the pathways. With the nitrogen-containing flue gas, things get a bit more interesting: nitrogen helps free up extra methane, causing permeability to tick upward in the early stages. Ultimately, though, secondary CO₂ hydrate formation takes over, pushing permeability down by as much as 79% in samples with high water content.
“We have experimentally demonstrated how gas permeability changes in hydrate-bearing rocks directly during the methane-to-CO₂ replacement process,” commented Evgeny Chuvilin, Leading Research Scientist at 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.”
Armed with these insights, engineers planning commercial gas extraction in the Arctic can move forward with much sharper predictive models, factoring in water content to fine-tune injection regimes and forecast production volumes with far greater precision.
The findings have just been published in the journal Natural Gas Industry B.
Skoltech is part of the VEB.RF Group.