How customized chemical recipes are revolutionizing oil recovery in challenging heterogeneous reservoirs
Imagine pouring water into a complex maze of sand and rock, trying to push out the hidden oil trapped within. For decades, this has been the fundamental challenge of oil recovery. While conventional methods can extract some oil, significant amounts—up to 60% or more of the original oil in place—often remain trapped in the reservoir after primary and secondary recovery methods have been exhausted 5 .
Enter ASP flooding—a technological marvel that combines alkali, surfactant, and polymer in a sophisticated chemical cocktail to liberate this stranded resource. As a leading tertiary oil recovery method, ASP flooding can increase oil recovery by an impressive 18-23% over conventional methods 2 .
But to achieve such dramatic results, engineers must carefully design the chemical parameters, especially for challenging "second-type" layers with their complex permeability variations. This article explores the cutting-edge science behind optimizing ASP flooding for maximum efficiency in these stubborn reservoirs.
Oil often remains trapped after conventional methods
Increase in oil recovery with ASP flooding
Challenging layers with permeability variations
Before diving into the complexities of second-type layers, it's essential to understand the basic mechanisms of ASP flooding. Each component plays a distinct yet interconnected role in the oil displacement process:
Functions as a powerful cleaning agent that dramatically lowers interfacial tension between oil and water. Think of how dish soap cuts through grease—surfactant performs a similar function at the microscopic level, mobilizing trapped oil droplets that would otherwise remain stuck in rock pores 2 7 .
The synergy of these three components creates a recovery system far more effective than any single component could achieve alone. As one study notes, "The benefits of ASP flooding are both to effectively mobilize the residual oil and economically increase the recovery factor from a reservoir" 2 .
The development of ASP flooding would be straightforward if all reservoir rock were uniform. Unfortunately, nature prefers complexity. Second-type layers refer to heterogeneous reservoir zones with significant variations in permeability—essentially, sections containing both fast-flow channels and slow-flow resistance points 1 .
This heterogeneity creates a fundamental problem: when identical injection parameters are applied across different permeability zones, the chemical solution follows the path of least resistance through high-permeability streaks, bypassing significant oil in tighter zones. The result is inconsistent production and suboptimal recovery 1 .
| Layer Type | Permeability Range | Flow Behavior | ASP Flooding Challenge |
|---|---|---|---|
| Homogeneous | Consistent | Uniform front advancement | Straightforward parameter design |
| Second-type Heterogeneous | Wide variations (e.g., 300-1600 mD) | Channeling and fingering | Requires customized injection parameters |
| Highly Fractured | Extreme contrasts | Dominant fracture flow | Significant chemical loss |
This heterogeneity problem has long plagued the Daqing Oil Field in China, where ASP flooding has been extensively applied. As researchers noted, "Due to heterogeneity of second-type layers and the sameness of injection parameters, different permeability zones have different production status" 1 . The solution required a paradigm shift from standardized to customized chemical injection strategies.
The breakthrough came with developing a comprehensive design method that fully considers the unique characteristics of target zones. Rather than applying identical chemical recipes across diverse permeability zones, this new approach customizes injection parameters for individual wells based on specific reservoir characteristics 1 .
This systematic consideration of reservoir heterogeneity allows engineers to design chemical parameters that align with the specific flow characteristics of each zone. The goal is to improve the matching rate between injection parameters and target zones, ensuring that chemicals reach and mobilize oil from both high and low permeability sections 1 .
Field applications showed a 9.8% improvement in matching rate compared to conventional approaches 1 .
The design process represents a significant advancement over earlier ASP approaches that treated reservoirs as uniform systems. By acknowledging and addressing inherent variations in rock properties, this method promises to significantly enhance sweep efficiency—the measure of how thoroughly the displacing fluid contacts the reservoir.
To validate the customized design approach, researchers conduct sophisticated core flood experiments that simulate reservoir conditions. These experiments measure how effectively ASP formulations mobilize trapped oil from rock samples with different permeability characteristics.
Berea sandstone cores saturated with brine and crude oil
Establish residual oil saturation before ASP injection
0.5 pore volume ASP slug at controlled rate
Post-ASP flooding simulation
| Surfactant Concentration (wt%) | Solution Viscosity (mm²/s) | Interfacial Tension (mN/m) |
|---|---|---|
| 0.2 | 1.75 | 0.323 |
| 0.4 | 2.53 | 0.192 |
| 0.7 | 5.12 | Not reported |
| Alkali Concentration (wt%) | Solution Viscosity (mm²/s) | Interfacial Tension (mN/m) |
|---|---|---|
| 0.0 | 2.53 | 0.192 |
| 0.2 | 2.53 | 0.085 |
| 0.8 | 2.53 | 0.024 |
| 1.0 | 2.53 | Not reported |
The experiment yielded compelling results. Using the optimal surfactant and alkali concentrations (0.4 wt% and 0.8 wt%, respectively), the tertiary oil recovery reached 16.3% of the original oil in place. The polymeric surfactant demonstrated exceptional performance, maintaining stable viscosity while achieving ultra-low interfacial tension values as low as 0.024 mN/m 2 .
| Reagent/Chemical | Primary Function | Research Considerations |
|---|---|---|
| Polymeric Surfactant (PMES) | Lowers interfacial tension & provides viscosity | Concentration optimized for balance between IFT reduction and favorable mobility ratio 2 |
| Alkali (Sodium Carbonate) | Generates in-situ surfactants & reduces adsorption | Higher concentrations improve IFT but may cause scaling; optimal concentration balances benefits and drawbacks 2 9 |
| Hydrolyzed Polyacrylamide (HPAM) | Increases viscosity for mobility control | Concentration tailored to reservoir permeability and salinity conditions 5 7 |
| Crude Oil with Acid Components | Reacts with alkali to form petroleum soap | Total acid number affects alkali effectiveness and in-situ surfactant generation 2 |
| Synthetic Brine | Replicates reservoir water chemistry | Salinity and divalent ions affect chemical performance and require formulation adjustments 2 |
The transition from laboratory success to field implementation represents the ultimate test for any enhanced oil recovery technology. Field applications of the customized ASP design method in Daqing Oilfield demonstrated impressive results, improving the matching rate of injection parameters with target zones by 9.8% compared to conventional approaches 1 .
Recent optimization research continues to refine ASP parameters. A 2025 simulation study analyzing 250 sensitivity runs identified optimal concentrations as:
With an optimal injection span of 8 years followed by chase water injection 3 . Such detailed optimization ensures maximum economic and recovery efficiency.
As global energy demand continues to evolve, efficient resource recovery becomes increasingly important. The future of ASP flooding lies in advanced simulation models that better capture the complex synergistic interactions between chemical components and reservoir rocks.
Recent research has developed more sophisticated numerical simulation approaches that couple viscosity variation, IFT reduction, and multicomponent adsorption phenomena. These advanced models demonstrate "better agreement with experiment results compared with that of the traditional model" 4 , promising more accurate predictions of field performance.
Scientists are exploring novel chemical formulations that can withstand higher reservoir temperatures and salinities, expanding ASP applicability to more challenging environments. The development of polymeric surfactants that maintain viscosity stability across a wide range of alkali concentrations represents just one example of these innovations 2 .
As these technological advancements continue, ASP flooding promises to unlock significant additional oil resources from mature fields around the world, extending productive lives and maximizing recovery from existing infrastructure. The careful design of polymer parameters for second-type layers exemplifies how targeted scientific approaches can overcome nature's complexities to meet our energy needs.
The science of ASP flooding represents a remarkable convergence of chemistry, physics, and engineering aimed at solving one of the oil industry's most persistent challenges. The development of customized design methods for second-type layers highlights how understanding and adapting to reservoir heterogeneity can dramatically improve recovery efficiency.
As research continues to refine chemical formulations and injection strategies, ASP flooding stands poised to unlock billions of barrels of oil that would otherwise remain trapped in complex reservoirs. This ongoing innovation journey demonstrates how scientific creativity and persistence continue to push the boundaries of what's possible in resource recovery, proving that even the most stubborn oil can be encouraged to flow with the right chemical persuasion.