Advanced Investigation of Hydrolyzed Polyacrylamide Gels with High-Purity Silica Nanoparticles under Fractured Reservoir Conditions

In the deep underground reservoirs where oil is trapped, a persistent problem plagues the extraction process: water. As oil wells age, they often begin to produce vast quantities of water alongside the valuable crude oil. This unwanted water is not just a nuisance; it is a costly and environmentally difficult burden to manage, requiring expensive separation and disposal while shortening the life of the reservoir. To stop this flood, engineers use a technique called water shut-off, which involves injecting a gel into the ground. Think of this gel as a temporary, flexible plug that flows into cracks and high-permeability zones, hardening to block the water's path while allowing oil to continue flowing through. However, the harsh conditions deep underground—extreme heat and salty water—often cause these gels to break down or shrink, expelling their water and failing to do their job.

Researchers at Amirkabir University of Technology and Heriot-Watt University set out to improve these gels by adding a specific type of tiny particle: high-purity silica nanoparticles. These are microscopic spheres of pure glass, far smaller than a grain of sand, designed to reinforce the gel's structure. While other studies have looked at similar particles, this team focused on how these specific high-purity particles behave under the dynamic, flowing conditions of a fractured reservoir, rather than just in a quiet, still container. They wanted to know if these particles could help the gel survive the heat and pressure of the real world, and if they could be injected effectively without clogging the rock before reaching the target zone.

The team began by mixing a standard polymer gel, known as hydrolyzed polyacrylamide, with their high-purity silica nanoparticles. They tested how quickly the mixture turned from a liquid into a solid gel, a process called gelation. They found that adding the nanoparticles made the gel form faster. A mixture with no nanoparticles took two days to fully harden, while a mixture with a small amount of nanoparticles hardened in just one day, and a slightly higher concentration hardened in less than a day. This speed is crucial for field applications, as it allows the gel to set before it flows too far away from the injection point.

Next, the researchers examined how the mixture flowed, which is vital for pumping it deep underground. They discovered that the amount of nanoparticles mattered greatly. When they added a small amount, specifically 0.2 percent by weight, the mixture became thinner and easier to pump, while still maintaining its ability to stretch and bend without breaking. This made the gel more resilient, capable of withstanding the stress of flowing through rock cracks. However, when they increased the amount of nanoparticles to 0.4 percent, the mixture became thicker and more prone to clumping. The extra particles did not spread out evenly, creating a less uniform structure that was harder to inject and less flexible. The team concluded that the lower concentration of 0.2 percent offered the best balance of easy injection and structural strength.

The study then turned to the gel's ability to survive high temperatures, specifically at 90 degrees Celsius, which is typical for many oil reservoirs. Over time, gels can suffer from a process called syneresis, where the network shrinks and squeezes out water, causing the plug to fail. The researchers found that the gel with 0.2 percent nanoparticles maintained its shape remarkably well over a month, showing very little water loss. In contrast, the gel with the higher concentration of 0.4 percent initially held its water well but eventually began to expel it more rapidly as time went on. The higher concentration seemed to create too many chemical bonds, leading to a structure that became brittle and unstable under long-term heat stress. The lower concentration, by interacting gently with the polymer chains, provided a more stable environment that resisted breaking down.

To see how the gel performed in a real-world scenario, the team conducted experiments using a piece of rock that had been artificially cracked to simulate a fractured reservoir. They injected the optimized gel into this rock and waited for it to set. After 72 hours, they tested how well the gel blocked the flow of fluids. The results were striking: the gel reduced the flow of water by a factor of 58.2, while reducing the flow of oil by a factor of 28.2. This means the gel was twice as effective at blocking water as it was at blocking oil, which is exactly the desired outcome for water shut-off operations. The gel successfully targeted the water pathways without completely sealing off the oil.

The researchers also observed that the gel behaved differently inside the rock than it did in a bottle. When the liquid gel traveled through the narrow crack in the rock, it took longer to harden than it did in a static container. This delay was likely caused by the physical forces of the flow and the dilution of the gel as it moved through the rock. This finding is important because it suggests that engineers must account for these delays when planning where and when to inject the gel in a real field.

Ultimately, this study demonstrates that adding a precise, small amount of high-purity silica nanoparticles can significantly improve the performance of water shut-off gels. By making the gel easier to pump, more flexible, and more resistant to heat, the 0.2 percent formulation offers a promising solution for managing unwanted water production in fractured reservoirs. The work provides a clear path forward for designing stronger, more reliable gels that can operate effectively under the demanding conditions of the oil industry, potentially extending the life of aging wells and reducing the environmental impact of water production.