Project Background

A mature sandstone reservoir in Southeast Asia had been under water flooding for more than 15 years. As production progressed, water cut levels increased significantly, reaching over 88% in several production wells.

Reservoir heterogeneity and high-permeability streaks caused early water breakthrough and inefficient sweep of remaining oil.

Key reservoir parameters:

• Reservoir temperature: 72–80°C

• Formation water salinity: 55,000–68,000 ppm TDS

• Average permeability: 450–900 mD

• Oil viscosity: Moderate

The operator sought a polymer flooding solution to improve mobility control and extend field life.

Technical Challenge

Conventional water flooding showed poor mobility ratio between injected water and crude oil. The injected water preferentially flowed through high-permeability channels, bypassing significant volumes of recoverable oil.

Previous polymer trials using standard HPAM grades experienced:

• Noticeable viscosity reduction in high salinity water

• Partial mechanical degradation during injection

• Uneven injection profile across zones

A more salt-tolerant and shear-stable PHPA polymer was required.

Polymer Selection Strategy

An oilfield-grade PHPA polymer with controlled hydrolysis and high molecular weight was selected based on:

• Salinity compatibility testing

• Thermal stability analysis

• Injectivity simulation

• Core flooding laboratory evaluation

Polymer solution concentration was optimized between 0.15% and 0.25% depending on permeability layers.

Low-shear mixing equipment was used to preserve polymer molecular structure.

Field Implementation

The polymer injection program was conducted in a pilot area consisting of 5 injection wells and 12 production wells.

Implementation steps:

1. Gradual ramp-up of polymer concentration

2. Continuous viscosity monitoring at wellhead

3. Injection profile logging

4. Water cut tracking in offset production wells

Monitoring period: 10 months

Performance Results

After 6–10 months of polymer flooding:

• Average oil production increased by 9.4% in pilot wells

• Water cut growth stabilized and slightly declined in key producers

• Injection conformance improved across multiple layers

• Reduced water channeling observed in high-permeability zones

• No severe injectivity loss reported

Reservoir simulation indicated improved mobility ratio and more uniform displacement front.

Technical Interpretation

The improved performance was attributed to:

• Increased injection water viscosity

• Reduced mobility ratio between water and oil

• Enhanced volumetric sweep efficiency

• Better conformance control in heterogeneous layers

• Salt-resistant polymer stability in formation brines

The PHPA polymer maintained sufficient viscosity despite elevated salinity, demonstrating strong compatibility with formation water conditions.

Economic Impact

The pilot phase demonstrated:

• Measurable incremental oil production

• Extended productive life of mature wells

• Improved water management efficiency

• Positive economic return within projected timeframe

Based on pilot results, the operator approved expansion of the polymer flooding program.

Conclusion

This case confirms that properly selected salt-resistant PHPA polymer can significantly improve mobility control in mature reservoirs with high salinity conditions.

By optimizing viscosity design, injection strategy, and monitoring protocols, polymer flooding can enhance oil recovery while maintaining operational stability.

Technical Support

Bluwat Chemicals provides:

• Reservoir matching analysis

• Polymer viscosity design support

• Salinity and temperature compatibility testing

• Laboratory core flooding evaluation guidance

• Long-term polymer supply for EOR projects

Contact our technical team for customized polymer flooding solutions.