Polymer-enhanced Foam Research Articles

Effect of CO2 Concentration on the Performance of Polymer-Enhanced Foam at the Steam Front.

This study examines the impact of CO2 concentration on the stability and plugging performance of polymer-enhanced foam (PEF) under high-temperature and high-pressure conditions representative of the steam front in heavy oil reservoirs. Bulk foam experiments were conducted to analyze the foam performance, interfacial properties, and rheological behavior of CHSB surfactant and Z364 polymer in different CO2 and N2 gas environments. Additionally, core flooding experiments were performed to investigate the plugging performance of PEF in porous media and the factors influencing it. The results indicate that a reduction in CO2 concentration in the foam, due to the lower solubility of N2 in water and the reduced permeability of the liquid film, enhances foam stability and flow resistance in porous media. The addition of polymers was found to significantly improve the stability of the liquid film and the flow viscosity of the foam, particularly under high-temperature conditions, effectively mitigating the foam strength degradation caused by CO2 dissolution. However, at 200 °C, a notable decrease in foam stability and a sharp reduction in the resistance factor were observed. Overall, the study elucidates the effects of gas type, temperature, and polymer concentration on the flow and plugging performance of PEF in porous media, providing reference for fluid mobility control at the steam front in heavy oil recovery.

Study on the Control of Steam Front Mobility in High-Temperature and High-Salinity Conditions Using Polymer-Enhanced Foam.

This study investigated the enhancing effects of the temperature-resistant polymer Poly(ethylene-co-N-methylbutenoyl carboxylate-co-styrenesulfonate-co-pyrrolidone) (hereinafter referred to as Z364) on the performance of cocamidopropyl hydroxy sulfobetaine (CHSB) foam under high-temperature and high-salinity conditions. The potential of this enhanced foam system for mobility control during heavy oil thermal recovery processes was also evaluated. Through a series of experiments, including foam stability tests, surface tension measurements, rheological assessments, and parallel core flooding experiments, we systematically analyzed the interaction between the Z364 polymer and CHSB surfactant on foam performance. The results indicated that the addition of Z364 significantly improved the strength, thermal resistance, and salt tolerance of CHSB foam. Furthermore, the adsorption of CHSB on the polymer chains enhanced the salt resistance of the polymer itself, particularly demonstrating stronger blocking effects in high-permeability cores. The experimental findings showed that Z364 increased the viscosity of the liquid film, slowed down liquid drainage, and reduced gas diffusion, effectively extending the half-life of CHSB foam and improving its stability under high-temperature conditions. Additionally, in parallel core flooding experiments, the polymer-enhanced foam exhibited significant flow diversion effects in both high-permeability and low-permeability cores, effectively directing more fluid into low-permeability channels and improving fluid distribution in heterogeneous reservoirs. Overall, Z364 polymer-enhanced CHSB foam demonstrated superior mobility control during heavy oil thermal recovery, offering new technical insights for improving the development efficiency of high-temperature, high-salinity reservoirs.

Unlocking the enormous potential of biological materials: Polymer-assisted foam for enhanced oil recovery in fractured porous media

In natural fractured reservoirs, foam serves as an effective method for mobility control, leading to a significant enhancement in oil recovery. However, the harsh conditions of reservoirs present challenges to the strength and stability of foams. In this study, we conducted comprehensive experimental research, employing a combination and screening approach, to successfully develop a super foam using biomacromolecules (Welan gum) and bio-based surfactants (APG). Bulk foam tests were carried out and the performance of foam flooding in fractured porous media was evaluated. The results demonstrated that the introduction of Welan gum significantly increased the strength of the foam and improved its rheological properties. The Welan gum-enhanced foam (WG-foam) exhibited higher flow resistance in fractured reservoirs, resulting in enhanced oil recovery. Compared to traditional hydrophobically associating polymer-enhanced foam (HAPAM-foam), the WG-foam showed a remarkable half-life for drainage of 20 h, which is 13 times longer than that of HAPAM-foam. Furthermore, the ultimate oil recovery of WG-foam was 21% higher than that of HAPAM, reaching 87%. Through molecular dynamics simulations, we uncovered the exceptional water-binding capacity of Welan gum, which significantly delayed the drainage rate in the foam lamella, thus enhancing foam stability. This work not only provides a powerful technical approach for foam-enhanced oil recovery, but also offers new insights into the fabrication of high-performance foams.

Influence of Different Reservoir Conditions on the Stability and Decay Mechanism of the Polymer-Enhanced Foam

Influence of Different Reservoir Conditions on the Stability and Decay Mechanism of the Polymer-Enhanced Foam

Evaluation of the Performances of Foam System as an Agent of Enhancing Oil Recovery

Foam has been used in petroleum engineering to enhance oil recovery for many years. It is a very complicated dispersion system, and the performances are affected by many factors. In order to understand the influence rules and mechanisms of such factors, the performances and mechanisms of foam systems are investigated by static and core flooding experiments with Sodium Dodecyl Sulfate. It is found that a polymer may reduce the foaming ability, but significantly enhance the foam stability in both oil-free and oil-bearing environments, while the optimal concentration is around 1500 mg/L in this case. NaCl may reduce the stability, but the capability of enhancing the foaming ability and oil tolerance gradually increases and stabilizes when the concentration reaches to 7000 mg/L. Oil can reduce the foam stability, and the stability decreases as the oil saturation increases to 0.15. Moreover, the foam stability is worse in light oil conditions than in heavy oil conditions. In the sand-pack tests, the resistance factors of foam are much higher than that of a polymer solution. The maximum resistance factor of the foam tested reaches about 230. The residual resistance factor of polymer-enhanced foam (PEF) is generally larger than that of pure foam and salt enhanced foam (SEF) in an oil-free environment. The maximum value of resistance factor of PEF and SEF is only about 60, and that of pure foam is less than 40 in an oil-bearing environment. In the parallel sand-pack tests, both ultimate oil recovery and incremental oil recovery are the best when using PEF, with SEF the second, and pure foam the worst.

Effect of sodium alginate and polyvinyl alcohol polymers on the foaming performance of dodecyl dimethyl betaine solutions

The zwitterionic ionic surfactant dodecyl dimethyl betaine (BS-12) exhibits both positive and negative charges simultaneously, and the charged nature of the incorporated polymer may impact the performance of BS-12. In this paper, the characteristics of anionic composite foam solutions formed by the electrostatic interaction between -COO- of sodium alginate (SA) and -NH+ of BS-12, as well as the zwitterionic composite foam solutions formed by hydrogen bonding between polyvinyl alcohol (PVA) and BS-12, were utilized to investigate the effects of SA and PVA, respectively, as stabilizers on the foam properties of their solutions. The results showed that the pure BS-12 solution exhibited excellent foaming performance, while the defoaming rate after 5 min reached over 90%. In both types of polymer-enhanced foam systems, the addition of PVA resulted in a decrease in foaming performance for BS-12 and was only effective in improving the foam stability of BS-12 at high concentrations of the foam solution. In contrast, the addition of SA exhibited a positive synergistic effect on the composite system BS-12 foam solution, with an optimal foaming concentration of 1 wt% BS-12 and 0.2 wt% SA. However, its impact on the stability performance of low-concentration BS-12 foam solutions was more significant than that of high-concentration ones. Therefore, the type and concentration of polymer should be strictly controlled in the practical application of BS-12, and we suggest using anionic polymers with low concentrations to improve the foaming and foam stability of BS-12 in practical application.

Polymer enhanced foam for improving oil recovery in oil-wet carbonate reservoirs: A proof of concept and insights into the polymer-surfactant interactions

The feasibility of polymer enhanced foam (PEF) for enhanced oil recovery (EOR) in a strongly oil-wet and heterogeneous carbonate reservoir with medium temperature (131 °F) and high salinity was experimentally investigated. An Alkyl Poly-Glycoside (APG) surfactant was firstly selected because of its prominent foam behavior in oil-wet carbonates. The effect of polymer type, flow rate and brine composition on foam strength and stability were systematically investigated, aiming to understand how the interactions between polymer and surfactant could influence the transport behavior and performance of PEF in porous media. It was found that, with either an associative polymer or a nonionic polymer (PAM), the foam strength and foam stability could be largely enhanced, both in the absence and in the presence of oil. A significant improvement in oil recovery efficiency was obtained for PEF with an associative polymer, approximately 5% higher than that achieved for conventional polymer-free foam. The PEF behavior is intimately dependent on the interactions between the polymer and the surfactant. It is hypothesized that the increased foam strength by adding polymer at oil-wet conditions may be resulted from an increase of aqueous phase viscosity, the wettability alteration from oil-wet to less oil-wet, the generation of a highly viscoelastic film and (or) the creation of a more stable pseudo-emulsion film. This study provides a robust approach for PEF mobility control and reservoir conformance in oil-wet and heterogeneous carbonate reservoir under analogous reservoir conditions.

Characteristics of CO2 foam plugging and migration: Implications for geological carbon storage and utilization in fractured reservoirs

Fractured reservoirs exhibit heterogeneity and high conductivity, posing challenges to the application of low-carbon and clean production technologies. In this study, the flow and plugging characteristics of CO2 foam in fractured cores were analyzed in physical fracture cores and visual slab fracture models. The influence of surface roughness and fracture openings on foam flow and plugging efficiency were studied. Results show that polymer-enhanced foam displays a higher-pressure drop in a single core with a small fracture opening. With increasing fracture opening, the plugging capacity of the polymer-enhanced foam gradually decreases to that of ordinary foam. In parallel fractures of different openings, ordinary foam is better able to regulate the flow, whereas the conformance control of polymer-enhanced is more robust. Prolonged foam flow in the fractures leads to foam collapse, especially for small fracture openings and high roughness. For such a core, the difference in distance lapsed by the upper and lower ends of the polymer-enhanced foam front is greater than that of the ordinary foam, and the bubble collapse during migration is less. For a given surface roughness, the smaller the fracture opening, the greater the resistance to foam flow. However, the resistance brought forth by surface roughness is greater, for a given fracture opening. Foam flow in the fracture is analyzed in terms of the forces acting on the foam. Understanding foam flow resistance is a key to preventing gas channeling, expanding sweep range and improving the oil washing efficiency.

Insights into the flow behaviour of the pre-generated polymer enhanced foam in heterogeneous porous media during tertiary oil recovery: Effect of gravitational forces

Over the past few decades, foam flooding has emerged as a decent option for diverting flow from high permeable layers toward dense layers. Here, a visualization study of the conventional foam and polymer enhanced foam (PEF) behavior in the heterogeneous porous media is presented and the PEF performance in horizontal and vertical injection modes is evaluated. A heterogeneous porous medium made of transparent plexiglass packed with two different layers of glass beads to attain a heterogeneity ratio of 4:1 was used in various flooding experiments. The results of dynamic tests in the absence of oil showed that the presence of polymer in the foaming solution increases the flow resistance of foam in the porous medium and prevents foam fingering in the low-permeable layers. Horizontal oil displacement experiments showed that PEF flooding has an excellent plugging capacity and oil recovery increased by 72.5% of water flooded residual oil (S*or), which was 19.1% more than that of conventional foam injection. Comparison between vertical and horizontal PEF flooding proved that due to the positive gravity effect, the performance of PEF in vertical mode was better than that in horizontal mode, and the recovery factor increased to 78.3% water-flooded residual oil.

Stable foam systems for improving oil recovery under high-temperature and high-salt reservoir conditions

Foams have high apparent viscosity when flowing in porous media, therefore foam flooding could significantly improve unfavorable mobility ratios, increase sweep efficiency, and enhance oil recovery. However, the applications of foam flooding in high-temperature and high-salt reservoirs are seriously restricted as foam systems often have inferior foamability and stability in these reservoirs. In this study, to improve foam flooding effectiveness in high-temperature and high-salt reservoirs, novel foam systems with excellent stability and plugging capacity are developed by combining surfactants, additives, and polymers. The performance of bulk foam, physical properties of the solutions, and properties of foam systems in core-flow experiments are investigated to determine the synergistic effects among the components of the foam systems and their foamability and plugging effect in cores. In foam systems with sodium alcohol ether sulfate (AES) and dodecylhydroxypropyl sulfobetaine (DHSB) as surfactants, and dodecanol as additive, the combination of the components makes surface tension decreased and surface dilatational modulus increased, therefore the foamability and stability of the systems are improved. The results of core-flow experiments under high-temperature and high-salt conditions show that these combined systems require low injection rate for foam generation in reservoirs, which is beneficial for foam regeneration in reservoirs. Moreover, to further improve the foam performance, a hydrophobically associating water-soluble polymer (HAWP) is employed. The interactions between HAWP and the surfactants reduce the critical association concentration of HAWP, and result in the increase of solution apparent viscosity and foam stability. The results of core-flow experiments under high-temperature and high-salt conditions show that polymer-enhanced foam systems could significantly increase the sealing pressure, widen the sealing permeability range, and deal with the gas-channeling problem of foam flooding. These foam systems could provide a potential technical pathway for improving the effectiveness of foam flooding in high-temperature and high-salt reservoirs.

Foamability and stability of anionic surfactant-anionic polymer solutions: Influence of ionic strength, polymer concentration, and molecular weight

A systematic experimental approach was initiated to optimize properties of a polymer enhanced foam (PEF) system using anionic surfactant (i.e., AOS) and anionic polymer (i.e., SAV10 MPM) in high salinity conditions. First, the bulk foam properties of AOS surfactant solutions as a function of AOS concentration and salinity were evaluated. The result indicated that Ca2+ ions increased the AOS foamability and foam stability more than Mg2+ ions within the solubility limit, where only the divalent ionic strength (Mg2+/Ca2+) ratio varied within brine composition. Second, the effect of SAV10 MPM concentration and different molecular weights of this polymer on AOS foamability and foam stability were investigated in modified synthetic seawater (MSSW1). We found that the AOS foamability and foam stability improved by SAV10 MPM addition but it's highly dependent on the polymer concentration. The AOS foamability and foam stability were boosted when the polymer concentration was below the critical overlap concentration (c*) in comparison to AOS without polymer. However, above polymer c*, the polymer tends to exhibit antifoam characteristics due to the hydrophobic nature of the polymer. Hence, to enhance anionic-anionic PEF systems, one should inhibit the hydrophobic interaction by maintaining the polymer concentration below c*. Thus, we recommend a low concentration of sulfonated polymer (i.e., SAV10 series, below c*) to enhance the AOS foamability and foam stability in a high salinity environment regardless of viscosity and molecular weight.

Visualization study of polymer enhanced foam (PEF) flooding for recovery of waterflood residual oil: Effect of cross flow

Foam injection is an emerging EOR technology that increases oil recovery by reducing gas mobility, especially in heterogeneous reservoirs with permeability variations. Foam can divert flow from high permeability regions to low permeability regions, provided that its stability is high enough to maintain pressure. In this work, a visualization study of foam flow through a two-layer heterogeneous model is presented and the performance of a surfactant-polymer mixture as the foam stabilizer is evaluated. We compared the efficiency of conventional foam (stabilized by a surfactant) and polymer enhanced foam (PEF) flooding (stabilized by a combination of surfactant and PVA polymer) in the glass bead packed models with three permeability ratios (PR) including 2:1, 4:1, and 8:1. Our particular interest was to visualize the effect of the cross-flow mechanism on PEF performance. To achieve the desired permeability ratio, the model was packed with different sizes of glass beads ranging from 150 to 600 μm. The conventional foam and PEF were injected at the tertiary mode for the recovery of waterflood residual oil. Both foam and PEF injection were significantly more efficient than the gas injection; however, the PEF front advancement was more pistonwise; the ultimate oil recovery by PEF flooding was 15–20% more than the conventional foam flooding in all cases of heterogeneous packed models. At higher permeability contrast of the porous medium that the ability of the foam to sweep the porous medium decreases, the PEF still performs better through the cross-flow mechanism due to its higher stability. This makes the PEF injection a more decent candidate for fractured reservoirs where the heterogeneity contrast is high.

Study on the regional characteristics during foam flooding by population balance model

Foam flooding is an effective method for enhancing oil recovery in high water-cut reservoirs and unconventional reservoirs. It is a dynamic process that includes foam generation and coalescence when foam flows through porous media. In this study, a foam flooding simulation model was established based on the population balance model. The stabilizing effect of the polymer and the coalescence characteristics when foam encounters oil were considered. The numerical simulation model was fitted and verified through a one-dimensional displacement experiment. The pressure difference across the sand pack in single foam flooding and polymer-enhanced foam flooding both agree well with the simulation results. Based on the numerical simulation, the foam distribution characteristics in different cases were studied. The results show that there are three zones during foam flooding: the foam growth zone, stable zone, and decay zone. These characteristics are mainly influenced by the adsorption of surfactant, the gas–liquid ratio, the injection rate, and the injection scheme. The oil recovery of polymer-enhanced foam flooding is estimated to be 5.85% more than that of single foam flooding. Moreover, the growth zone and decay zone in three dimensions are considerably wider than in the one-dimensional model. In addition, the slug volume influences the oil recovery the most in the foam enhanced foam flooding, followed by the oil viscosity and gas-liquid ratio. The established model can describe the dynamic change process of foam, and can thus track the foam distribution underground and aid in optimization of the injection strategies during foam flooding.

CO2 Foam and CO2 Polymer Enhanced Foam for Heavy Oil Recovery and CO2 Storage

Enhanced oil recovery (EOR) from heavy oil reservoirs is challenging. High oil viscosity, high mobility ratio, inadequate sweep, and reservoir heterogeneity adds more challenges and severe difficulties during any EOR method. Foam injection showed potential as an EOR method for challenging and heterogeneous reservoirs containing light oil. However, the foams and especially polymer enhanced foams (PEF) for heavy oil recovery have been less studied. This study aims to evaluate the performance of CO2 foam and CO2 PEF for heavy oil recovery and CO2 storage by analyzing flow through porous media pressure profile, oil recovery, and CO2 gas production. Foam bulk stability tests showed higher stability of PEF compared to that of surfactant-based foam both in the absence and presence of heavy crude oil. The addition of polymer to surfactant-based foam significantly improved its dynamic stability during foam flow experiments. CO2 PEF propagated faster with higher apparent viscosity and resulted in more oil recovery compared to that of CO2 foam injection. The visual observation of glass column demonstrated stable frontal displacement and higher sweep efficiency of PEF compared to that of conventional foam. In the fractured rock sample, additional heavy oil recovery was obtained by liquid diversion into the matrix area rather than gas diversion. Aside from oil production, the higher stability of PEF resulted in more gas storage compared to conventional foam. This study shows that CO2 PEF could significantly improve heavy oil recovery and CO2 storage.

Monitoring Polymer-Enhanced Foam Displacements Through Heterogeneous Porous Media: A Pore-Scale Study

AbstractIn this work, fundamental understanding of phase displacements involved in polymer-enhanced air foam is investigated which was not well discussed in the available literature. To do this, a series of foam injection experiments were performed on heterogeneous rock-look-alike micromodels in the presence and absence of a single fracture. The models were initially saturated with crude oil and experienced post polymer-enhanced foam injection process. We observed for the first time the mechanism of synergetic upstream snap-off and lamella division in the vicinity of the area where the permeability contrast was obvious. Observations showed two opposite effects of oil emulsioning and bubble coalescence when gas bubbles came in contact with oil in pore bodies. Fractal dimension analysis of front polymer-enhanced foam illustrates a noticeable improvement in oil displacement. Primary enhanced foam injection to oil saturated micromodel causes bubble coarsening which leads to less efficient oil displacement process. The lower the polymer concentration, the less stable the foam; consequently, the less efficient oil displacement is observed. Lower viscosity oil results in lower recovery efficiency as the stability of foam decreases. To shed light on the dynamic behavior of polymer–surfactant interface, some dynamic surface tension tests were conducted. Results showed that repellency between surfactant and polymer molecules causes surfactant molecules to be present on the surface making the initial dynamic interfacial tension (IFT) decrease. Results of this work help to better understand how polymer could enhance the efficiency of foam floods in heterogeneous systems.

Polymer-Enhanced Foam Flooding for Improving Heavy Oil Recovery in Thin Reservoirs

Oil reserves of the thin heavy oil reservoirs are estimated to be over 400 billion barrels. The recovery factor of water-flooding in these reservoirs is as low as 10–20% due to the high oil viscosi...

Experimental evaluation of polymer-enhanced foam transportation on the foam stabilization in the porous media

With the addition of polyacrylamide homopolymer (PAM) to the foam solution which is known as polymer-enhanced foam (PEF), the lamella strength in the surface could be enhanced and subsequently the membrane liquid drainage is weakened, and the diffusion of gas phase would reduce. In this comprehensive study, the comparison of different types of polymers on the property of a foaming agent is taken into the experimental evaluation. To do this, polyacrylamide homopolymer (PAM), flopaam (FA920) with the mixture of surfactants and its comparison with the utilization of only surfactants are being evaluated to generate the polymer-enhanced foam (PEF) in the porous medium. Furthermore, the performances of the foaming agent are analyzed regarding the pressure drop measurement at the displacement of the foam and the resistance factor of the gas phase (RFgas) is investigated. Consequently, polymer addition would increase the RFgas regarding the more propagation of foam in the porous media which has caused more foam stabilization. The property of PEF is utterly dependent on the type of used polymer, and according to the results, the amphiphilic polymer has experienced more resistance due to more reactions with a surfactant.

A Pore Scale Study of Non-Newtonian Effect on Foam Propagation in Porous Media

CO2 injection is one of the most promising techniques to enhance oil recovery. However, an unfavorable mobility ratio, reservoir heterogeneity and gravity segregation can reduce the macroscopic sweep efficiency. In situ foaming of injected CO2 is the method that has the most potential for improving sweep efficiency based on controlling CO2 mobility. This study investigates the foaming behavior of N,N,N′-trimethyl-N′-tallow-1,3-diaminopropane (DTTM) surfactant with CO2 in a transparent porous microflow model with natural rock pore structures. It focuses on the effect of the salinity induced non-Newtonian behavior of DTTM solution on foam propagation. The performance of foams stabilized by 0.5 wt% DTTM solution over the viscosity range from 0.71 (at 5 wt% NaCl) to 41 cp (at 20 wt% NaCl) was compared with conventional polymer-enhanced foams whose liquid phase contained a commonly used foaming surfactant, C15–18 Internal Olefin Sulfonate (C15–18 IOS) and a hydrolyzed polyacrylamide. Such comparisons have also provided insight into the respective impacts of liquid phase viscosification by worm-like surfactant micelles and polymer on foam texture associated with its rheological characteristics. It was found that at low aqueous phase viscosity (injection liquid viscosity of 0.71 cp) the maximum achievable viscosity of DDTM foam was around 1000 cp, which was 80 times IOS stabilized foam. The interfacial tension of DTTM was higher than that of IOS, resulting coarser foam texture and higher individual lamella resistance. An increase in DTTM solution viscosity by a factor of 33 decreased foam generation and viscosity for gas injection. This was not observed for the simultaneous injection of gas and DTTM solution. Overall, the effect of liquid phase viscosity on transient foam behavior during gas injection is similar for both DTTM and IOS regardless of the difference in the nature of viscosifying agents (WLM vs 3330 s polymer). An increase in gas injection pressure without liquid injection delayed foam propagation and reduced the magnitude of foam viscosity. The results from this study indicated that DTTM surfactant is an important alternative to commercially available polymers that have been used to enhance foam performance in porous media. This particular surfactant type also overcomes several disadvantages of polymers such as limited temperature and salinity tolerance, shear degradation, and filtering in low permeability formations.

Static and Dynamic Performance of Wet Foam and Polymer-Enhanced Foam in the Presence of Heavy Oil

Inadequate sweep efficiency is one of the main concerns in conventional heavy oil recovery processes. Alternative processes are therefore needed to increase heavy oil sweep efficiency. Foam injection has gained interest in conventional oil recovery in recent times as it can control the mobility ratio and improve the sweep efficiency over chemical or gas flooding. However, most of the studies have focused on light crude oil. This study aims to investigate the static and dynamic performances of foam and polymer-enhanced foam (PEF) in the presence of heavy oil. Static and dynamic experiments were conducted to investigate the potential of foam and PEF for heavy oil recovery. Static analysis included foam/PEF stability, decay profile, and image analysis. A linear visual sand pack was used to visualize the performance of CO2 foam and CO2 PEF in porous media (dynamic experiments). Nonionic, anionic, and cationic surfactants were used as the foaming agents. Static stability results showed that the anionic surfactant generated relatively more stable foam, even in the presence of heavy oil. Slower liquid drainage and collapse rates for PEF compared to that of foam were the key observations through foam static analyses. Besides improving heavy oil recovery, the addition of polymer accelerated foam generation and propagation in porous media saturated with heavy oil. Visual analysis demonstrated more stable frontal displacement and higher sweep efficiency of PEF compared to conventional foam flooding. Unlike foam injection, lesser channeling (foam collapse) was observed during PEF injection. The results of this study will open a new insight on the potential of foam, especially polymer-enhanced foam, for oil recovery of those reservoirs with viscous oil.

Transport of polymer stabilized foams in porous media: Associative polymer versus PAM

Polymer addition to surfactant is known to enhance foam flood in porous media, however, the choice of polymer type and its possible interactions with the surfactant is still a research concern.The objective of this paper is to compare the effect of different polymer types on foam generation and propagation in porous media. Two types of polymer, nonionic and associative, were used alone or with surfactant to evaluate their ability to generate and propagate a Polymer Enhanced Foam (PEF) in porous media. Foaming performance is evaluated by measuring the pressure drop during foam displacement and compared to the one phase gas flow through the Resistance Factor (RFgas). It appears clearly that if the RFgas is very low when injecting gas alone or along with PAM, its value increases significantly when gas is co-injected with surfactant solution alone but this increase is more marked when surfactant is mixed with polymer. PEF behavior depends strongly on polymer type, we show that amphiphilic polymer leads to stronger resistance than PAM due to interactions with surfactant.To interpret our experimental data, we present a pore scale scenario that sketches lamellae behavior and the interactions between surfactant and polymer that illustrates the core scale data.