A Comprehensive Evaluation of Alkaline Surfactant Polymer Flooding and Hybrid Process for Enhanced Oil Recovery
- Cuong Dang (Computer Modelling Group Ltd) | Long Nghiem (Computer Modelling Group Ltd) | Ngoc Nguyen (University of Calgary) | Zhangxin Chen (University of Calgary) | Chaodong Yang (Computer Modelling Group Ltd) | Wisup Bae (Sejong University)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 9-11 October, San Antonio, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2017. Society of Petroleum Engineers
- 5 Reservoir Desciption & Dynamics, 5.7.2 Recovery Factors, 5.3.2 Multiphase Flow, 5.5.2 Core Analysis, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.4 Improved and Enhanced Recovery, 2 Well completion, 2.4 Hydraulic Fracturing, 5.2.2 Fluid Modeling, Equations of State, 5.4.1 Waterflooding, 5.5 Reservoir Simulation, 5.3.6 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.7 Reserves Evaluation, 5.4 Improved and Enhanced Recovery, 5.2 Fluid Characterization
- Hybrid EOR, Low Salinity Waterflooding, Enhanced Oil Recovery, Chemical Flooding
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This paper presents recent advances in the subject of modeling and optimization of ASP (Alkaline, Surfactant and Polymer) flooding with: (1) a critical review of the state-of-the-art development of ASP flooding; (2) an efficient and accurate novel approach for ASP modeling for robust simulation of chemical processes in conjunction with oil, gas, and water flash calculations using an equation of state (EOS) simulator; (3) systematic validation of the new modeling approach with laboratory studies; (4) evaluation of a hybrid Low Salinity ASP recovery process; and (5) robust optimization of ASP field-scale design under geological uncertainties.
We used a new approach that can model the behavior of the surfactant-oil-water-microemulsion system based on solubility data. In the Type III system, the emulsion is distributed judiciously between the oil and water phases without the need to introduce a third liquid phase. This model captures most of the important physical and chemical phenomena in the ASP process. The model was then validated with numerous coreflooding experiments conducted by different research institutes as well as with a specialized chemical flood simulator. The newly proposed model is tested using different injection schemes and chemical formulations including negative salinity gradient, non-negative salinity gradient, and a series of benchmark coreflooding experiments. Excellent agreements between the model and the experiments in terms of oil recovery and pressure drop were achieved for all corefloods. In addition, the model was also proven to be highly consistent with both UTCHEM-EQBATCH and UTCHEM-IPHREEQC. More importantly, previous results obtained without the explicit modeling of Type III indicated that the recovery factor deviates significantly from the experimental data, whereas the pseudo two-phase approach in this paper gives an excellent match in all cases. This model has also been successfully applied to match the recovery of Alkaline-CoSolvent-Polymer flooding, which is a promising recovery approach.
We investigated the potential of hybrid low salinity ASP flooding in which Low Salinity Waterflooding (LSW) was implemented in secondary production and followed by ASP flooding. This approach can provide a superior performance compared to the conventional chemical flooding because it provides better oil recovery in the secondary stage and promotes the synergy between low salinity environment and ASP slugs. Finally, the proposed robust optimization workflow helps to increasea project NPV and significantly reduces the uncertainty range associated with geology.
|File Size||4 MB||Number of Pages||40|
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