In the world of oil recovery, the real challenge begins after easy extraction methods are exhausted.
After the initial gush and the secondary water floods, up to half of a reservoir's original oil often remains trapped in the complex pore networks of underground rock. This is particularly true in what petroleum engineers call "second-type layers"—reservoirs with moderate permeability that lie between highly productive zones and tight, stubborn formations. Extracting this remaining resource requires sophisticated technology, and Alkaline-Surfactant-Polymer (ASP) flooding has emerged as one of the most effective methods.
This advanced technique represents a paradigm shift from simply pushing oil with water to engineering chemical interactions at the microscopic level. By designing the perfect chemical cocktail, engineers can mobilize oil that has resisted all previous recovery attempts. The design of polymer parameters specifically for second-type layers presents a fascinating scientific challenge—one that balances fluid dynamics, chemistry, and geology to achieve what was once thought impossible.
At its core, ASP flooding is a chemical enhanced oil recovery method that combines three distinct agents that work in synergy:
Functions as a cost-effective foundation, typically sodium carbonate. It interacts with natural acids in the crude oil to generate in-situ surfactants, reducing the need for expensive commercial surfactants. Additionally, it helps reduce the adsorption of other chemicals onto rock surfaces and can alter rock wettability to a more water-wet state, making oil easier to displace 1 .
Molecules are the peacemakers between oil and water. With their hydrophilic (water-loving) heads and hydrophobic (oil-loving) tails, they congregate at the interface between oil and water, dramatically reducing interfacial tension by several orders of magnitude. This reduction allows trapped oil droplets to deform and move through pore throats that previously held them captive 1 .
Typically hydrolyzed polyacrylamide (HPAM), serves as the mobility control agent. By increasing the viscosity of the injection fluid, it improves the mobility ratio between displacing fluid and displaced oil. This results in better volumetric sweep efficiency, preventing the injected fluid from fingering through the path of least resistance and instead encouraging contact with untouched oil 1 2 .
Compatible water prepares the reservoir by flushing out incompatible formation brine 1
The main chemical cocktail (15-30% of pore volume) that mobilizes residual oil 1
Polymer-thickened water that protects the ASP slug from dissipation 1
Drives the chemical bank through the reservoir until economic limit 1
Second-type layers present a unique set of characteristics that complicate recovery efforts. These medium-permeability zones have often been bypassed by previous flooding operations due to reservoir heterogeneity—the natural variation in rock properties that causes fluid to flow preferentially through high-permeability pathways.
After initial polymer flooding, this heterogeneity often intensifies, creating "more favorable seepage channels and cross-flow of displacement fluids" 3 . The result is an inefficient circulation where chemical agents follow the path of least resistance through high-permeability zones while bypassing significant oil in adjacent moderate-permeability layers.
The design challenge for second-type layers centers on creating a chemical system that can effectively navigate these complex pore networks. The polymer component must be carefully tailored to provide sufficient viscosity for mobility control without causing plugging in narrower pore throats. This balancing act requires sophisticated experimental protocols and a deep understanding of fluid-rock interactions.
Recent research has provided valuable insights into optimizing ASP formulations for challenging reservoir conditions. One comprehensive study focused on designing an effective ASP formula under low-salinity conditions, where traditional salinity gradient approaches are limited 2 .
The research team employed a systematic experimental methodology to determine optimal chemical formulations:
Researchers first screened various chemical combinations by analyzing their phase behavior—observing how oil, water, and chemicals interact and separate under different conditions. The key measurement was the solubilization ratio, which indicates how effectively the chemical system can dissolve and mobilize oil 2 .
By testing ASP formulations across a range of salinities, the team identified the "optimum salinity" where the system achieves the lowest interfacial tension—approximately 1.25% NaCl in this case 2 .
This critical step determined appropriate polymer concentrations by measuring the risk of plugging in pore throats. The team filtered polymer solutions through membrane filters with specific pore sizes and calculated the filtration ratio—a key indicator of injectivity 2 .
The final and most comprehensive test involved flooding actual reservoir core samples with the optimized ASP formulation to measure oil recovery performance under simulated reservoir conditions 2 .
The experimental results demonstrated the success of this systematic approach:
| Component | Chemical | Concentration/Ratio | Function |
|---|---|---|---|
| Alkali | Sodium Carbonate (Na₂CO₃) | 1 wt% | Generate in-situ surfactants, reduce chemical adsorption |
| Surfactant | LAS:DOSS mixture | 1:4 weight ratio | Reduce oil-water interfacial tension |
| Co-solvent | Diethylene Glycol Monobutyl Ether (DGBE) | 5 wt% | Enhance surfactant performance, prevent gels and liquid crystals |
| Polymer | Hydrolyzed Polyacrylamide (HPAM) | 3000-3300 mg/L | Mobility control, improve sweep efficiency |
Most impressively, the coreflooding tests confirmed the field applicability of this optimized formula, achieving "an 86.2% recovery rate of residual oil after extensive waterflooding" 2 . This remarkable recovery demonstrates the potential of properly designed ASP flooding for recovering oil that would otherwise remain permanently trapped.
The filtration ratio testing provided crucial guidance for polymer concentration selection, identifying 3000-3300 mg/L as the optimal range that provided adequate viscosity without excessive plugging risk 2 . This finding is particularly relevant for second-type layers, where pore throats may be more constricted than in high-permeability zones.
| Polymer Concentration (mg/L) | Filtration Ratio | Plugging Risk | Suitability for Second-Type Layers |
|---|---|---|---|
| <2500 | High | Low | Good mobility but potentially insufficient viscosity |
| 2500-3000 | Moderate | Low to Moderate | Balanced performance |
| 3000-3300 | Acceptable | Moderate | Optimal range for target viscosity |
| >3300 | Problematic | High | Unacceptable plugging risk |
Designing effective ASP formulations requires a sophisticated array of chemical agents and analytical tools. Here are the key components researchers use to develop optimal recipes for second-type layers:
| Reagent Category | Specific Examples | Function in Experiments |
|---|---|---|
| Alkaline Agents | Sodium Carbonate (Na₂CO₃), Sodium Hydroxide (NaOH) | Maintain optimal pH, generate in-situ surfactants, reduce chemical adsorption on rock surfaces 1 2 |
| Surfactants | Linear Alkylbenzene Sulfonate (LAS), Dioctyl Sulfosuccinate (DOSS), Petroleum Sulfonates | Lower interfacial tension between oil and water, enable mobilization of trapped residual oil 2 |
| Polymers | Hydrolyzed Polyacrylamide (HPAM) with varying molecular weights | Increase viscosity of displacing fluid, improve mobility ratio, enhance sweep efficiency 2 3 |
| Co-solvents | Diethylene Glycol Monobutyl Ether (DGBE), Isobutyl Alcohol (IBA) | Enhance surfactant performance, prevent formation of gels and liquid crystals, improve chemical stability 2 |
| Salinity Modifiers | Sodium Chloride (NaCl) | Adjust brine composition to achieve optimum salinity for minimum interfacial tension 2 |
While ASP flooding shows tremendous potential, its implementation faces significant practical challenges that must be addressed in the design phase, particularly for second-type layers.
Research has revealed that strong alkaline chemicals can react with reservoir minerals, leading to "various degrees of scaling" that block pore throats and reduce injectivity 4 . This issue is particularly pronounced in lower permeability zones, where studies found that "the core with lower permeability will suffer more serious reservoir damage" 4 .
Economic considerations also play a crucial role in design decisions. The timing of switching to subsequent water flooding after ASP injection significantly impacts project economics.
Recent advances using machine learning have helped optimize this timing, with one study reporting potential economic improvements of "752.1 million CNY by the end of the flooding process" through optimized injection strategies 5 .
As the energy industry continues to evolve, ASP flooding technologies are advancing in sophistication. The integration of supramolecular chemistry represents a particularly promising frontier. These systems utilize non-covalent interactions—such as hydrophobic association, hydrogen bonding, and electrostatic interactions—to create chemical structures with responsive properties 6 .
For instance, host-guest recognition systems using cyclodextrin polymers have demonstrated the ability to "increase the solution viscosity, viscoelasticity and emulsion stability even at low polymer concentration" 6 . Such advances could prove particularly valuable for second-type layers, where injectivity challenges often limit chemical concentrations.
Additionally, hybrid low salinity ASP flooding approaches are showing superior performance by combining the benefits of low salinity waterflooding with chemical methods .
This integration provides "better oil recovery in the secondary stage and promotes the synergy between a low salinity environment and ASP slugs" .
The design of polymer parameters for ASP flooding in second-type layers represents a fascinating intersection of chemistry, physics, and engineering. What appears at surface level to be simply injecting chemicals underground reveals itself as a deeply sophisticated process of molecular engineering tailored to specific geological constraints.
As research continues to refine our understanding of chemical interactions in porous media, the potential for recovering additional trapped oil grows accordingly. The systematic, experimental approach to designing ASP formulations—particularly the polymer parameters that control mobility—ensures that each reservoir receives a custom recipe rather than a one-size-fits-all solution.
In an energy-conscious world where efficiency matters more than ever, technologies like ASP flooding represent not just a means of extending oil production, but a demonstration of human ingenuity in maximizing the utility of natural resources while minimizing waste. The second-type layers that once presented frustrating obstacles are now becoming opportunities for scientific innovation and improved recovery.