Activated aluminum helped increase heavy oil displacement efficiency from reservoir rock by nearly two-thirds. This was demonstrated by tests conducted by researchers from the Institute of Metallurgy and Ore Beneficiation, K. Turysov University, the national oil and gas company KazMunayGas, and Satpayev University in Kazakhstan at the Karazhanbas field.
High viscosity is one of the main factors complicating heavy oil production. Because of this, oil does not flow easily through the reservoir, so even with conventional waterflooding, a significant portion remains trapped in the pore spaces. One method to enhance oil recovery involves treating the near-wellbore zone with a specialized aluminum alloy containing gallium, indium, and tin. These elements disrupt the oxide film that rapidly forms on ordinary aluminum surfaces and prevents its reaction with water. As a result, upon contact with formation water, the alloy continues to react vigorously, releasing hydrogen and heat directly within the reservoir. This is expected to reduce oil viscosity and facilitate its flow toward the wellbore.
To verify the effectiveness of this technology, the researchers conducted a series of laboratory experiments using rock models saturated with high-viscosity oil.
In the first experiment, the activated alloy interacted only with formation water. Despite releasing about 2.6 liters of hydrogen from just 3 grams of the alloy, the oil displacement coefficient remained at 39%. This indicated that hydrogen and heat alone are insufficient to enhance oil recovery.
In the second experiment, a 3% hydrochloric acid solution and 2% nonionic surfactant were added to the system. The acid destroyed the oxide film and accelerated the reaction, while the surfactant converted the evolved gas into a stable foam within the rock matrix. As a result, although the volume of hydrogen released was slightly lower, precisely about 2.1 liters, the oil displacement coefficient rose to 61%. Moreover, nearly 17 ml of additional oil was recovered not only during the treatment itself, but also during subsequent waterflooding, indicating an improvement in the filtration properties of the near-wellbore zone.
In the researchers’ view, the technology’s effectiveness is determined not by the amount of hydrogen evolved, but by the combination of several simultaneous processes. The heat released reduces oil viscosity, the gas-liquid foam helps direct water into previously unflushed zones of the reservoir, and the chemical treatment facilitates oil movement through the pore space.
The researchers then assessed the technology’s prospects using a computer-generated model of the Karazhanbas field. Calculations showed that results vary significantly depending on the specific well. In some cases, the production gain was barely noticeable, while in others it reached 3.27 cubic meters of oil per day. In the scientists’ view, this can be explained by the fact that treatment effectiveness is determined not only by the reagent itself, but also by the current state of the reservoir, specifically, oil saturation, water cut, reservoir pressure, and the hydrodynamic connectivity of the well to oil-saturated zones. Proper well selection will therefore be one of the key conditions for successful implementation of the new technology.
