Khodaparast, Pooya (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park) | Johns, Russell T. (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park)
Surfactant floods can attain high oil recovery if optimum conditions with ultra-low interfacial tensions (IFT) are achieved in the reservoir. A new equation-of-state (EoS) phase behavior model based on the hydrophilic-lipophilic difference (HLD-NAC) has been shown to fit and predict phase behavior data continuously throughout the Winsor I, II, III, and IV regions. The state-of-the-art for viscosity estimation, however, uses empirical non-predictive models based on fits to salinity scans, even though other parameters change, such as the phase number and compositions. In this paper, we develop the first-of-its-kind microemulsion viscosity model that gives continuous viscosity estimates in composition space. This model is coupled to our existing HLD-NAC phase behavior EoS.
The results show that experimentally measured viscosities in all Winsor regions (two and three-phase) are a function of phase composition, temperature, pressure, salinity, and
Current HLD-NAC theory and most simulators represent multicomponent mixtures with three lumped components, where the excess phases are also assumed pure. This can cause significant errors, and discontinuities in chemical flooding simulation for surfactant mixtures. We coupled the HLD-NAC and pseudo-phase models to develop an EOS for microemulsions where surfactant, polymer, alcohol, alkali and monovalent/divalent ions can partition differently into the excess phases and microemulsion phase as temperature and pressure are changed.
We develop a pseudo-phase model to calculate partitioning of components between lumped components or namely pseudo-phases. The pseudo-phase model is based on a transformed composition space. The partitioning model is based on different mechanisms such as cation exchange like reactions for ions and surfactant hydration properties. Next, the three-pseudo-component HLD-NAC EOS is used to calculate curvature of the interface and microemulsion phase composition based on pseudo-phases. That is, the microemulsion phase consists of a curved ruled surface between water and oil pseudo-phases. Polymer partitioning is updated based on micelle radius. Finally, the phase compositions are converted back from pseudo-phase space to the original composition space.
This model is the first comprehensive and mechanistic flash calculation algorithm based on HLD-NAC and pseudo-phase theory to calculate microemulsion properties for mixtures without the assumption of pure excess phases. This algorithm allows for modeling of the chromatographic separation of surfactant, soap, alcohol, alkali and polymer components in chemical flooding processes. Current microemulsion models usually ignore the differing partitioning of components between excess and microemulsion phases, generating discontinuities that slow computational time and adversely impact accuracy.
The objective of this research was to develop a model to predict the optimum phase behavior of chemical formulations for a given oil based on the molecular structure of the surfactants and co-solvents. The model is sufficiently accurate to provide a useful guide to an experimental testing program for the development of chemical EOR formulations. There are thousands of combinations of surfactants and co-solvents that could be tested for each oil, so even approximate predictions are very useful in terms of reducing the time and effort required for testing and for prioritizing the chemical combinations to test that are most likely to yield ultra-low IFT at reservoir conditions. The effects of changing molecular structures (e.g. swapping head groups, swapping hydrophobes, increasing the length of hydrophobes, increasing the number of PO and EO groups, adjusting the ratios of surfactants) are shown. The variables with the greatest impact on the optimum salinity and solubilization ratio were identified, and methods are proposed to shift the optimum salinity and the optimum solubilization ratios in any desired direction. The structure-property model was developed and tested using a large dataset consisting of 684 microemulsion phase behavior experiments using 24 oils. The chemical formulations used 85 surfactants and 18 co-solvents in various combinations. Both optimum salinity and optimum solubilization ratio (and thus IFT) are modeled whereas other models have focused almost exclusively on the optimum salinity. Predicting the optimum solubilization ratio is actually of more value because of its relationship to IFT. The models include the effects of co-solvent partitioning, soap formation and the molecular structure of both the surfactants and co-solvents.
Dang, Cuong (Computer Modelling Group Ltd.) | Nghiem, Long (Computer Modelling Group Ltd.) | Nguyen, Ngoc (University of Calgary) | Yang, Chaodong (Computer Modelling Group Ltd.) | Mirzabozorg, Arash (Computer Modelling Group Ltd.) | Li, Heng (Computer Modelling Group Ltd.) | Chen, Zhangxin (University of Calgary)
Many attempts have been made to understand, design, and optimize a chemical flooding process; however, the current low oil price environment makes its implementation very challenging from an economics point of view. Recently, CoSolvent Assisted Chemical Flooding (CACF) has been considered as a promising approach to reduce the cost of surfactant-based recovery methods, especially in heavy oil reservoirs. More importantly, recent studies indicated that CACF can be efficiently applied at relatively low temperature, i.e., without the need of steam injection. This helps reduce for the cost of steam generation and injection, and the associated greenhouse gas effects. This paper presents a new development in modeling CACF using an Equation-of-State (EOS) compositional reservoir simulator.
We used a new approach to model the behavior of the oil-water-microemulsion system based on solubility data without modeling type III microemulsion explicitly. The results showed an excellent agreement with numerous chemical coreflooding data and are in agreement with a chemical floodingresearch simulator. The new development presented includes the effects of cosolvent on rheological properties and phase behavior of microemulsion in the CACF process, particularly microemulsion viscosity and interfacial tension.
The proposed model showed good agreement with four published CACF coreflood experiments in which surfactant was not used in alkali and polymer chemical slugs. This model efficiently captures the complex chemical reactionsoccurring in the CACF process, i.e., generation of in-situ soap based on reactions between alkali and a rich acid component in heavy crude oil. The model provides consistent results with laboratory coreflood data at different operating temperatures, which is very important for heavy oil reservoirs. The ultimate recovery factor by CACF coreflooding is about 97%, similar to ASP (Alkali, Surfactant and Polymer) coreflooding, but without the need of surfactant injection.
Doorwar, Shashvat (Chevron Energy Technology Company) | Lee, Vincent (Chevron Energy Technology Company) | Davidson, Andrew (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Traditionally, all surfactant processes require viscous polymer to mobilize the oil bank. Recent literature shows that for highly dipping reservoirs, a continuous surfactant injection process can be stabilized with gravity alone, by slowing down the processing rate. We extend the gravity stable approach for surfactant slug processes and demonstrate the importance of maintaining gravity stability between slug and chase in addition to gravity stability between microemulsion and slug. Four sandpack experiments were conducted and pictures of the sandpack were taken at regular intervals to provide visual evidence of stable or unstable interfaces. Different color dyes were used to aid visualization of clear fluids. Gravity-stabilized surfactant-only processes eliminate the need of polymer and other facilities associated with surfactant polymer or alkali-surfactant-polymer processes. The slug process described in this paper is a significant improvement on the continuous surfactant injection gravity stable process published earlier.
Izadi, M. (Ecopetrol S.A.) | Vicente, S. E. (Ecopetrol S.A.) | Zapata Arango, J. F. (Ecopetrol S.A.) | Chaparro, C. (Ecopetrol S.A.) | Jimenez, J. A. (Ecopetrol S.A.) | Manrique, E. (Ecopetrol S.A.) | Mantilla, J. (Ecopetrol S.A.) | Dueñas, D. E. (Ecopetrol S.A.) | Huertas, O. (Ecopetrol S.A.) | Kazemi, H. (Colorado School of Mines)
Surfactant-polymer (SP) flooding (also known as micellar flooding) is an enhanced oil recovery (EOR) process resulting from the interaction of three mechanisms: (1) oil solubilization, (2) interfacial tension reduction, and (3) aqueous-phase mobility reduction by polymer. Surfactant-polymer flooding has been studied both in the laboratory and field pilot tests for several decades. In SP flooding, traditionally a tapered polymer solution follows the injected surfactant slug. However, in recent years, co-injection of surfactant and a relatively high concentration of polymer solution has been used in several field trials. Despite a significant increase in oil recovery in several surfactant-polymer flood projects, the increased oil production period has been of short duration.
The first objective of this paper is to present two field pilot tests which encountered productivity impairment, and the second objective is to describe the probable causes of the productivity impairment. The third objective of the paper is to present a methodology, using field and laboratory data, to anticipate the nature of long-term problems. To shed light on the issues, we will present two pilot tests located in the Illinois basin in the United States and San Francisco Field in Colombia. The results of the pilot tests and several laboratory experiments will be presented to address the productivity loss observed in the two pilot projects. Laboratory measurements to determine crude oil propensity for emulsions, with and without surfactants, are not part of the routine chemical EOR protocol in the industry. Nonetheless, understanding the cause and type of emulsion formation in crude oil, brine, and polymer at different salinities is critical and will be presented in the paper. In addition, in the paper, we will present the results of a numerical simulator to evaluate experimental laboratory results and the field test performance. In conclusion, because of the experience with numerous laboratory experiments and the conduct of associated field tests, we will be able to shed light on the complexity of surfactant-polymer EOR field applications.
Maubert, M. (The University of Texas at Austin) | Jith Liyanage, P. (The University of Texas at Austin) | Pope, G. (The University of Texas at Austin) | Upamali, N. (The University of Texas at Austin) | Chang, L. (The University of Texas at Austin) | Ren, G. (Total E&P R&T) | Mateen, K. (Total E&P R&T) | Ma, K. (Total E&P R&T) | Bourdarot, G. (Total E&P) | Morel, D. (Total E&P)
Alkaline-surfactant-polymer (ASP) coreflood experiments using Indiana limestone were conducted to test the effectiveness of sodium hydroxide in reducing surfactant retention on limestones. Low concentrations of sodium hydroxide of only about 0.3 wt% increase the pH to about 12.6. The high pH reduces the adsorption of anionic surfactants by changing the surface charge of the limestone from positive to negative as well as having other favorable geochemical effects. Sodium carbonate could not be used in these experiments to increase the pH because the Indiana Limestone rock contained gypsum, which causes calcium carbonate to precipitate when it dissolves. Another advantage of sodium hydroxide is that much lower concentrations are needed compared to sodium carbonate because of its lower molecular weight. No adverse reactions between the sodium hydroxide and limestone were observed and the propagation of the pH in the corefloods was observed to be extremely favorable. The tertiary oil recovery was high and the surfactant retention using sodium hydroxide was low compared to experiments without alkali and compared to typical retention values reported in the literature for carbonates.
This paper presents numerical modeling of low tension surfactant gas based EOR method. In this process, slugs of various surfactant solutions and gas are alternated injected to mobilize remained oil left from water flood. The objective of this paper is to model the mechanisms behind the process by history matching the experimental data and simulation of a field-scale reservoir pilot. A four-phase chemical flooding reservoir simulator (UTCHEM) was used to history match a published core flood experiment and simulate a pilot-scale case. The results from the history match reveale that interfacial tension (IFT) reduction between oil and water by surfactant, displacement of oil by gas, and the mobility control of gas are the main mechanims lead to a substantioal increase in oil recovery. Based on these key findings, modeling of the low-tension surfactant-gas flood shows that such a process is very positive for low permeability reservoirs with a 90% oil recovery of the initial oil saturation (Sio=0.56) in a coreflood experiment and a range of recovery factors between 50% to 70% of the water flood in large scale cases.
Arachchilage, Gayani W. P. Pinnawala (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Davidson, Andrew (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Chemical costs dominate surfactant enhanced oil recovery (EOR) processes. A measure of chemical usage is the pore volume of chemical injected multiplied by the concentration of the chemical in the formulation (PV*C). Recent developments have reduced PV*C to about 30 units for conventional surfactant processes and to about 10 units for ASP processes. Our goal was to demonstrate high oil recovery using conventional surfactant processes at PV*C of 10 units. Under these conditions surfactant polymer flooding becomes just as viable an alternative for oil recovery as the more complex ASP processes.
In this paper, we conducted several phase behavior experiments with the goal of minimizing microemulsion viscosity and maximizing oil solubilization ratios. In addition, we focused on maintaining aqueous stability of both the surfactant slug and dilutions with polymer chase fluids. Both surfactant and co-solvent compositions were optimized to achieve low microemulsion viscosity. The microemulsion viscosity was also measured using three-phase relative permeability experiments. Once an appropriately low microemulsion viscosity was achieved, a series of corefloods at different PV*C units of surfactant were conducted in Bentheimer sandstone. Our baseline formulation included 2 wt% surfactant and 2.8 wt% co-solvent and recovered more than 95% oil in a surrogate Bentheimer coreflood using 30 units of surfactant. The existing surfactant formulation was optimized to match the new crude oil sample and it also recovered more than 95% oil in a Bentheimer coreflood using 30 units of surfactant.
By incorporating large hydrophobe surfactants, we achieved good phase behavior with 1.25% surfactant and 2% co-solvent. The optimized formulation recovered 98% oil with 20 units and 91% with 10 units of surfactant, which translated into a retention of <0.1 mg/g of surfactant. These results indicate that high-performance surfactant formulations have the potential to significantly reduce chemical cost and compete with conventional SP processes in terms of PV*C. Consequently, we illustrate the ability of recovering more than 90% oil with only 10 units of surfactant in conventional surfactant-polymer flooding with high performance surfactants. Such an approach can potentially compete with ASP processes and allow for rapid deployment due to reduced complexity.
Davidson, Andrew (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Unomah, Michael (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan
Low microemulsion viscosity is critical for the success of chemical EOR. Typical microemulsion viscosities are measured using a rheometer and are considered to be static measurements. Given that microemulsions have a propensity to show non-Newtonian behavior, static viscosity measurements are not scalable to dynamic viscosities observed in cores and hence difficult to scale-up to field designs using simulations. We present a technique to measure dynamic microemulsion viscosity using a modified two-phase steady state relative permeability setup. Such dynamic viscosities provide a more practical feel for microemulsion viscosity under reservoir conditions in the pores and allow for selection of low microemulsion viscosity formulations. A two-phase steady state relative permeability setup was used with continuous co-injection of oil and surfactant. A glass filled sand pack was used as a surrogate core and the injection fluids were allowed to equilibrate into the appropriate phases as determined by the phase behavior. For the rapidly equilibrating and low viscosity Winsor Type III formulations three phases are clearly observed in the sand packs. Using the phase cuts in the sand pack/effluent and the known oil and water viscosities, we can estimate the microemulsion viscosity. Both low and high viscosity formulations were tested in corefloods and oil recovery measured to illustrate the importance of low viscosity microemulsions for oil recovery. As expected, the low viscosity microemulsions correlated with higher oil recovery. In addition, the equilibration times to reach Winsor Type III microemulsions were also linked to better oil recovery. For the well behaved formulations that equilibrated in less than 2 days the static microemulsion viscosity correlated well with the dynamic viscosity. The modified steady state relative permeability setup can accurately estimate microemulsion viscosity and allow for better screening of surfactant formulations identified for field flooding. The dynamic microemulsion viscosities can also provide inputs for numerical simulation and better predict microemulsion behavior in the subsurface during field surfactant floods.