Reservoir Adaptability of Alkali-Free Flooding Systems in Medium- and Low-Permeability Reservoirs: An Integrated Evaluation Based on Multipoint Pressure Measurements and Microscopic Visualization

Deep beneath the earth's surface, vast networks of rock pores hold the world's remaining oil. For decades, engineers have used water to push this oil toward wells, but as the easy-to-reach oil is depleted, the industry has turned to more complex methods to squeeze out the rest. One such method involves injecting a cocktail of chemicals into the ground to loosen the oil from the rock and sweep it away. For many years, the most successful version of this cocktail included a strong base, similar to the lye found in drain cleaners, to help the chemicals work. However, this base is corrosive; it eats away at metal pipes, damages equipment, and creates a sludge of tiny rock particles that can clog the very pathways meant to carry the oil. As the industry moves toward older, harder-to-reach oil fields with smaller, more intricate rock pores, the need for a gentler, non-corrosive alternative has become urgent. The challenge is to find a chemical mix that is tough enough to move stubborn oil but gentle enough to flow through tight spaces without getting stuck or destroying the well.

Researchers at Southwest Petroleum University in China set out to solve this puzzle by testing two new, base-free chemical systems designed for these difficult, low-permeability reservoirs. They compared a simple two-part mixture of surfactant and polymer against a more complex three-part mixture that added salt to the blend. To see how these fluids would behave in the real world, they did not just rely on computer models or simple tests; they built a detailed experimental setup that allowed them to watch the fluids move through rock samples in real time. They used cores of sandstone with different levels of porosity, mimicking the tightness of the underground rock, and placed pressure sensors at multiple points along the rock to detect exactly where the flow was being blocked. They also used a flat, transparent model of the rock's pores to visualize how the fluids interacted with the oil, watching for the formation of thick, gel-like emulsions that could act as plugs.

The investigation revealed that the two chemical systems behaved very differently. The simpler two-part mixture, while effective at reducing the stickiness between oil and water, struggled to move through the rock. In the tightest rock samples, this fluid caused pressure to build up rapidly at the entrance, indicating that it was getting stuck immediately upon injection. When the researchers watched the fluid move through the transparent model, they saw that the mixture formed a thick, emulsified layer right at the inlet, effectively sealing the door and preventing the fluid from reaching the oil deeper inside. This "plugging" effect meant that even though the fluid was chemically capable of moving oil, it could never get far enough into the rock to do its job. The researchers found that this blockage was not just a matter of the chemicals sticking to the rock surface, but a dynamic issue where the fluid itself transformed into a barrier as it met the oil.

In contrast, the three-part mixture containing salt performed much better in the medium-permeability rocks, which represent a common target for future oil recovery. This system flowed more smoothly, maintaining a steady pressure as it moved through the rock. In the visual experiments, it created a clean, continuous front that pushed the oil forward without getting stuck at the entrance. The salt in the mixture helped the polymer molecules stay compact, allowing them to slip through the narrow pores more easily, while still maintaining enough thickness to push the oil effectively. This system also formed a stable emulsion that helped sweep the oil out of the rock pores without clogging the path. However, this success had a limit: in the very tightest rock samples (50 mD), this salt-based system also failed to inject properly, causing pressure to build up and block the entrance just like the simpler mixture. When the researchers ran a final test to measure how much oil they could actually recover in the medium-permeability rocks, the three-part salt system proved superior. It extracted 55 percent of the oil from the rock sample, significantly outperforming the two-part mixture, which recovered 48 percent, and a standard polymer solution, which recovered only 47 percent.

The study concludes that while removing the corrosive base was a necessary step for protecting equipment, simply swapping in a new chemical mix is not enough; the fluid must also be engineered to flow through the specific geometry of the rock. The researchers demonstrated that adding salt to the surfactant and polymer blend created a system that balanced the need to loosen the oil with the need to stay mobile, but only down to a certain level of rock tightness. This approach offers a promising path forward for developing oil fields that were previously considered too difficult or risky to treat with chemical flooding, provided the reservoir is not too tight. By combining pressure measurements with direct visual observation, the team provided a clear picture of where and why fluids fail, offering a practical guide for selecting the right chemical system for the right rock. The findings suggest that with the right formulation, it is possible to recover more oil from these challenging reservoirs without the engineering headaches caused by traditional, corrosive methods.