Siberia’s Subsurface Found to Contain Several Times More Water and Less Oil Than Previously Believed

Scientists at the National University of Oil and Gas “Gubkin University” (NRU) have analyzed core samples from the Bazhenov Formation – the shale oil-bearing stratum of Western Siberia – using a new method for studying the structure of rocks.

The analysis showed that the rocks of the formation in the region contain 1.5 to 7 times more water than previously believed. This means that earlier estimates of oil reserves in Western Siberia, made in the second half of the 20th century, were overstated, which requires a revision of approaches to its extraction.

The Bazhenov Formation is a layer of bituminous clay-siliceous source rocks that formed on the bottom of an ancient sea about 150 million years ago. For a long time, it was believed that these rocks were characterized by low water saturation. Estimates of reserves were based on this – calculated on the assumption that the rock’s pores were almost 85–100% saturated with oil. Using a new research method, Gubkin University scientists have shown that this is not the case and that strategies for the extraction and use of Western Siberia’s resources need to be revised.

The researchers applied a method of thermal analysis combined with gas spectrometry, developed in the Laboratory of Nanostructured Materials and Catalytic Processes for the Processing of Carbon-Containing Raw Materials at Gubkin University. It makes it possible to determine the water content in core samples of source rocks more accurately than previously known methods.

The essence of the method is that a rock sample is heated according to a specific protocol, and the vapors of water, hydrocarbons, and other gases released in the process are analyzed using infrared spectroscopy and mass spectrometry. This makes it possible not only to measure the total amount of water in closed and open pores, but also to see at what temperature it is released, which provides information about the structure of the pore space, the nature of its saturation, and the mineralogical composition of the rocks.

Analysis of core samples from the Bazhenov Formation showed that the water content in most of them ranges from 20 to 70%, depending on the field. According to the scientists, the real figures may be even higher – due to the loss of water and hydrocarbons when the core is brought to the surface.

“The Bazhenov Formation has been studied for more than half a century, yet from the point of view of extraction there is almost no effect. This is because for a long time the characteristics of these rocks – their microstructure – were simply assessed incorrectly. This was done according to standards developed in the mid-1950s and oriented toward classical reservoirs. The Bazhenov Formation is unique and differs from other rocks in its complex and specific pore space structure,” said Nikolay Mikhaylov, Professor of the Department of Development and Operation of Oil Fields.

The high water saturation of the Bazhenov Formation rocks means that along with every ton of oil, companies are forced to bring very large volumes of water to the surface. It must be separated, disposed of, or reinjected – this entails additional costs for equipment and technology.

The problem of water saturation manifests itself in such a method of field development as hydraulic fracturing. This technology involves injecting fluid into a well under high pressure to create fractures in the rock in order to increase the volume of rock drainage and the inflow of hydrocarbons.

“Previously it was believed that hydraulic fracturing would open the way only for oil, since there is almost no water in the formation. But in practice it turned out differently: hydraulic fracturing shakes up the entire fluid system, and that very water that was in small and closed pores begins to move and starts to flow together with the oil. That is why even now, in all horizontal wells with hydraulic fracturing in the Bazhenov Formation, high water cut is recorded – on average 30%, and in a significant portion of wells the water share reaches 70–100%,” the scientist explained.

The study changes the approach to forecasting the prospects for oil production and field development: the presence of water requires a different composition of reagents and special extraction technologies.