Experimental Study of In-Situ CO<Subscript>2</Subscript> Foam Technique and Application in Yangsanmu Oilfield

The Yangsanmu oilfield of Dagang is a typical heavy oil reservoir. After the maximum primary production (waterflooding), more than half of the original oil is still retained in the formation. Therefore, the implementation of an enhanced oil recovery (EOR) process to further raise the production scheme is inevitable. In this work, a novel in-situ CO₂ foam technique which can be used as a potential EOR technique in this oilfield was studied. A screening of gas producers, foam stabilizers and foaming agents was followed by the study of the properties of the in-situ CO₂ foam systems through static experiments. Core-flooding experiments and field application were also conducted to evaluate the feasibility of this technique. The results indicated that the in-situ CO₂ foam system can improve both the sweep and displacement efficiencies, due to the capacity of this system in reducing oil viscosity and interfacial tension, respectively. The EOR performance of the in-situ CO₂ foam system is better than the single-agent and even binary system (surfactant-polymer) flooding. The filed data demonstrated that the in-situ CO₂ technique can significantly promote oil production and control water cuts. These results are believed to be beneficial in making EOR strategies for similar reservoirs.     

Stabilization of natural gas foams using different surfactants at high pressure and high temperature conditions

Natural gas foam can be used for mobility control and channel blocking during natural gas injection for enhanced oil recovery, in which stable foams need to be used at high reservoir temperature, high pressure and high water salinity conditions in field applications. In this study, the performance of methane (CH₄) foams stabilized by different types of surfactants was tested using a high pressure and high temperature foam meter for surfactant screening and selection, including anionic surfactant (sodium dodecyl sulfate), non-anionic surfactant (alkyl polyglycoside), zwitterionic surfactant (dodecyl dimethyl betaine) and cationic surfactant (dodecyl trimethyl ammonium chloride), and the results show that CH₄-SDS foam has much better performance than that of the other three surfactants. The influences of gas types (CH₄, N₂, and CO₂), surfactant concentration, temperature (up to 110°C), pressure (up to 12.0 MPa), and the presence of polymers as foam stabilizer on foam performance was also evaluated using SDS surfactant. The experimental results show that the stability of CH₄ foam is better than that of CO₂ foam, while N₂ foam is the most stable, and CO₂ foam has the largest foam volume, which can be attributed to the strong interactions between CO₂ molecules with H₂O. The foaming ability and foam stability increase with the increase of the SDS concentration up to 1.0 wt% (0.035 mol/L), but a further increase of the surfactant concentration has a negative effect. The high temperature can greatly reduce the stability of CH₄-SDS foam, while the foaming ability and foam stability can be significantly enhanced at high pressure. The addition of a small amount of polyacrylamide as a foam stabilizer can significantly increase the viscosity of the bulk solution and improve the foam stability, and the higher the molecular weight of the polymer, the higher viscosity of the foam liquid film, the better foam performance.     

Solution Properties and Displacement Characteristics of in situ CO2 Foam System for Enhanced Oil Recovery

Carbon dioxide (CO₂) foam flooding has been shown to enhance oil recovery. However, large-scale adoption has been restricted by issues with transportation of CO₂ and equipment corrosion. In situ CO₂ foam generation can possibly overcome these issues. In this article, a CO₂ sustained-release system was first optimized for the CO₂ production rate and production efficiency. Then, the dissolution capacity and plug-removing ability of the sustained-release system were evaluated. Visual experiment and parallel sand pack flooding tests were conducted to verify the formation, propagation of in situ CO₂ foam, and the feasibility of this technique. The results indicated that the sustained-release system had benign ability to lower injection pressure and improve injectability. Moreover, in situ CO₂ foam flooding could obtain high oil recovery due to favorable mobility control ability, interfacial tension reduction capacity, and heterogeneity improvement. All the experiments demonstrated that the in situ CO₂ foam technique has great potential for enhanced oil recovery in the Bohai oilfield.     

Stability improvement of CO2 foam for enhanced oil‐recovery applications using polyelectrolytes and polyelectrolyte complex nanoparticles

CO₂ foam for enhanced oil‐recovery applications has been traditionally used in order to address mobility‐control problems that occur during CO₂ flooding. However, the supercritical CO₂ foam generated by surfactant has a few shortcomings, such as loss of surfactant to the formation due to adsorption and lack of a stable front in the presence of crude oil. These problems arise because surfactants dynamically leave and enter the foam interface. We discuss the addition of polyelectrolytes and polyelectrolyte complex nanoparticles (PECNP) to the surfactant solution to stabilize the interface using electrostatic forces to generate stronger and longer‐lasting foams. An optimized ratio and pH of the polyelectrolytes was used to generate the nanoparticles. Thereafter we studied the interaction of the polyelectrolyte–surfactant CO₂ foam and the polyelectrolyte complex nanoparticle–surfactant CO₂ foam with crude oil in a high‐pressure, high‐temperature static view cell. The nanoparticle–surfactant CO₂ foam system was found to be more durable in the presence of crude oil. Understanding the rheology of the foam becomes crucial in determining the effect of shear on the viscosity of the foam. A high‐pressure, high‐temperature rheometer setup was used to shear the CO₂ foam for the three different systems, and the viscosity was measured with time. It was found that the viscosity of the CO₂ foams generated by these new systems of polyelectrolytes was slightly better than the surfactant‐generated CO₂ foams. Core‐flood experiments were conducted in the absence and presence of crude oil to understand the foam mobility and the oil recovered. The core‐flood experiments in the presence of crude oil show promising results for the CO₂ foams generated by nanoparticle–surfactant and polyelectrolyte–surfactant systems. This paper also reviews the extent of damage, if any, that could be caused by the injection of nanoparticles. It was observed that the PECNP–surfactant system produced 58.33% of the residual oil, while the surfactant system itself produced 47.6% of the residual oil in place. Most importantly, the PECNP system produced 9.1% of the oil left after the core was flooded with the surfactant foam system. This proves that the PECNP system was able to extract more oil from the core when the surfactant foam system was already injected. © 2016 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2017 , 134, 44491.     

Comparative Investigation of Dynamic Foam Behavior of Air–Water and CO2–Water Systems

The purpose of this study was to understand and compare the dynamic foam behavior of the surfactant Tween‐20 in air–water and CO₂–water systems. The foam height in the CO₂–water system was less than that in the air–water system, but the foam stability was better in the CO₂–water system. The effect of temperature on axial dye displacement and foam bubble size was studied, where the foam generation ability of the surfactant was directly proportional to the temperature, while the foaminess was inversely proportional. The observed highest foam volume for the air–water system was 3922 ± 181 cm³ and for the CO₂–water system 3195 ± 181 cm³ at 5.0 g L^–1 of surfactant at air flow rate of 1 liter per minute (LPM) at 52 °C. The half‐life for the air–water and the CO₂–water system was 110 and 40 s, respectively, at 5.0 g L^–1 of surfactant at the air flow rate of 1 LPM and 28 °C. In wet foam, the liquid holdup range for the air–water system was 0.38–0.52% and for the CO₂–water system 0.51–0.72% in the concentration range 1.0–5.0 g L^–1 at 1 LPM gas flow rate.     

Synthesis of spherical zirconia by reverse emulsion precipitation

Spherical ZrO₂ microparticles were prepared in a three-phase reactor by mixing two water-in-oil emulsions with normal heptane as oil phase and aqueous solutions of zirconium oxyacetate and ammonia as water phases, respectively. The principal factors that influenced the stability of emulsion were investigated, including the surfactant type, the volume of w/o, and the concentration of zirconium ion. In this work, four anion surfactants were tested, including Span 85, Arlacel 83, Span 80 and Span 40. The most stable reverse emulsions were obtained with the surfactant Span 40. When w/o volume ratio was kept 1/100 using Span 40 or Span 80 as a surfactant, the ZrO₂ microparticles with spherical morphology were successfully prepared in the reverse emulsions at various Zr⁴⁺ concentrations (from 0.5 M to 3 M). The particle sizes of ZrO₂ are smaller for Span 40 as compared with Span 80 on the same Zr⁴⁺ concentrations. The crystalline phase of the ZrO₂ powders after calcination at 750 °C for 2 h was tetragonal.     

Stable CO2/water foam stabilized by dilute surface-modified nanoparticles and cationic surfactant at high temperature and salinity

CO₂ enhanced oil recovery and storage could see widespread deployment as decarbonization efforts accelerate to meet climate goals. CO₂ is more efficiently distributed underground as a viscous foam than as pure CO₂; however, most reported CO₂ foams are unstable at harsh reservoir conditions (22 wt% brine, 2200 psi, and 80°C). We hypothesize that silica nanoparticles (NP) grafted with (3-trimethoxysilylpropyl)diethylenetriamine ligands (N3), to improve colloidal stability, and dimethoxydimethylsilane ligands (DM), to improve CO₂-phillicity, combined with the cationic surfactant N¹-alkyl-N³, N³-dimethylpropane-1,3-diamine (RCADA), will develop viscous, stable CO₂ foams at reservoir conditions. We grafted NP with N3 and DM ligands. We verified NP stability at reservoir conditions with measurements of zeta potential, amine titration curves, and NP diameter. We measured NP water contact angles (θ_w) at the water–air and water–liquid CO₂ interfaces. In a high-temperature, high-pressure flow apparatus, we calculated the viscosity of CO₂ foams across a beadpack and determined static foam stability with microscope observations. Modified NP were colloidally stable at reservoir conditions for 4 weeks, and had higher θ_w in liquid CO₂ than in air. Addition of at least 0.5 μmol/m² DM silane (0.5DM) greatly improved foam stability. RCADA-only foam coarsening rates (dD_SM³/dt) decreased 16–17× after adding 1 wt/vol% 8N3 + 1.5DM NP, and 5–10× with a 0.1–1 vol/vol% increase in RCADA concentration (with or without NP). 1 vol/vol% RCADA foam exhibited coarsening rates of 900 and 2400 μm³/min with 1 and 0.2 wt/vol% 8N3 + 1.5DM NP, respectively. These results demonstrate impressive foam stabilities at harsh reservoir conditions.     

Investigation on Foam Self‐Generation Using In Situ Carbon Dioxide (CO2) for Enhancing Oil Recovery

In situ carbon dioxide (CO₂) foam flooding has proved to be economically feasible in the oil field, but its self‐generation behavior in the bulk scale/porous media is far from understood. In this study, the optimum in situ CO₂‐foaming agent was first screened, and then in situ foam was investigated in the bulk. In situ foam flooding was conducted to evaluate the displacement characteristics and enhanced oil recovery of this system. The results showed that the foaming agent comprising 0.5% sodium dodecyl sulfonate (SDS) + 0.5% lauramido propyl hydroxyl sultaine (LHSB) gave the best foam properties and that the in situ CO₂ foam with a slow releasing rate is effective both in bulk scale and in porous media, allowing a considerable enhancement of oil recovery in sand packs with different permeabilities.     

Surface Dilational Rheology,Foam, and Core Flow Properties of Alpha Olefin Sulfonate

The surface tension, surface dilational rheology, foaming and displacement flow properties of alpha olefin sulfonate (AOS) with inorganic salts were studied. The foam composite index (FCI), which reflects foaming capacity and foam stability, is used to evaluate foam properties. It is found that sodium and calcium salts can lead to decreases in AOS surface tension, critical micelle concentration, and molecular area at the gas–liquid interface. Sodium ions reduce the surface dilational viscoelasticity (E) and FCI of AOS, while calcium ions can enhance the E of AOS and make the FCI of AOS reach a maximum. In the solution containing calcium and sodium ions, the FCI of AOS is improved. Crude oil reduces the FCI of AOS. Injection pressure and displacing efficiency of AOS alternating carbon dioxide (CO₂) injection are higher than injections of water alternating with CO₂ or CO₂ alone in low permeability cores.     

低碳醇对氟碳与碳氢表面活性剂复配体系泡沫性能的影响

普通碳氢表面活性剂与磺基甜菜碱氟碳表面活性剂(FS)相比,泡沫性能和耐油性不好。醇通常强烈地影响表面活性剂的自组织行为,醇的加入能提高表面活性剂的泡沫性能。本文采用Ross-Miles法探讨了低碳醇对FS与阴离子碳氢表面活性剂(AOS)复配体系FS/AOS泡沫性能的影响。结果表明,当甲醇、无水乙醇、异丙醇浓度分别为5%、3%、3%,复配体系FS/AOS的起泡性能和泡沫稳定性仍较好,在加入醇之后,煤油含量60%～80%时起泡性能和泡沫稳定性仍较好。不同碳数的低碳醇对复配体系泡沫性能的影响规律为:发泡性能甲醇最好、异丙醇次之、无水乙醇最差,异丙醇的稳泡性能较甲醇和无水乙醇差。     

The pyrolysis behaviors of polyimide foam derived from 3,3′,4,4′‐benzophenone tetracarboxylic dianhydride/4,4′‐oxydianiline

The thermal stability and pyrolysis behaviors of polyimide (PI) foam derived from 3,3′,4,4′‐benzophenone tetracarboxylic dianhydride (BTDA)/4,4′‐oxydianiline (4,4′‐ODA) in air and in nitrogen were studied. The decomposition products of PI foam were analyzed by thermogravimetry‐Fourier transform infrared spectroscopy (TG‐FTIR). Several integral and differential methods reported in the literatures were used in decomposition kinetics analysis of PI foam. The results indicated that the PI foam was easier to decompose in air than in nitrogen, with ～ 55% residue remaining in nitrogen versus zero in air at 800^oC. The main pyrolysis products were CO₂, CO, and H₂O in air and CO₂, CO, H₂O, and small organic molecules in nitrogen. The different dynamic methods gave similar results that the apparent activation energies, pre‐exponential factors, and reaction orders were higher in nitrogen than those in air. © 2009 Wiley Periodicals, Inc. J Appl Polym Sci, 2010     

Spontaneous Oleofoams from Water-in-Oil Emulsions

Spontaneously foaming oil systems have been formulated from water-in-oil emulsions by the controlled release and entrapment of gas in emulsified water droplets contained within the oil. The cascade of events leading to their formation is as follows: Two Span 60-emulsified populations of water droplets, one containing Na₂CO₃, the other 10% HCl and caseinate, were mixed in miglyol oil; the controlled coalescence of Na₂CO₃ droplets with the HCl ones served as a microreactor for the pH reduction and the subsequent release of CO₂ from Na₂CO₃; these gas microbubbles were arrested by sodium caseinate, stabilizing a microfoam within the water droplets; these droplets expanded under the rising gas pressure, spontaneously transforming the surrounding oil into a foamy oleogel containing water droplets.     

Synthesis of spherical zirconia by precipitation between two water/Oil emulsions

Microparticles of ZrO₂ are produced by using precipitation method between two emulsion solutions. First, two solutions of stable reverse emulsion (water-in-oil) are prepared and mixed to form gelled precipitates, using normal heptane as the continuous oil phase and aqueous solutions of zirconium oxyacetate and aqueous ammonia as the suspending droplets. Through a series of operations, including distillation, filtration and washing, the dried precursors are obtained. After calcining the precursors at 750°C, ZrO₂ powder with a tetragonal structure is obtained. Principle factors that influence the emulsion stability, which subsequently affects the morphology and particle size of ZrO₂ powder, are investigated, including the type and concentration of surfactant, volume ratio of water/oil, concentration of solute in water phases, and mixing intensity and time for emulsion formation. Four kinds of anionic surfactants are put to test for emulsion stability; among them Span 40 and Span 80 are considered as suitable surfactants for producing spherical microparticles of ZrO₂, which has a size range from several hundred nanometers to micrometers depending on the synthesis conditions. ©     

Inhibition effect of CO2 on asphaltene precipitation for an Iranian crude oil and comparison with N2 and CH4

The effects of N₂, CH₄ and CO₂ injection on asphaltene precipitation have been experimentally investigated using a reservoir oil fluid from south of Iran, making use of light transmission method. The results are compared and the effects of injected gases on reducing asphaltene colloidal stability in oil are found in the following order: CH₄> N₂>CO₂. It is observed that CO₂ can act like an inhibitor and can increase the solubility of asphaltene, decreasing the asphaltene precipitation onset. A thermodynamic discussion explains the effect of CO₂ on the solubility of asphaltene based on the solubility parameters of recombined oil and CO₂, calculated from Peng-Robinson equation of state along with an empirical correlation for volumetric properties of CO₂.     

Oxidative stability of sunflower oil extracted with supercritical carbon dioxide

Extraction of oilseeds with supercritical carbon dioxide (SC−CO₂) is a promising technique to obtain vegetable oils. However, instability of such oils has been associated in the past with SC−CO₂ extraction. The reasons underlying such instability were unclear. Results presented here suggest that oil instability may be related to the oxygen content of CO₂. In fact, oil stability decreases sharply when refined oil (additive-free) is re-extracted with SC−CO₂ and can be related to the oxygen content in the CO₂. Never-theless, oil stability could be improved to the level of conventionally extracted oil by adding trace amounts of ascorbic acid.     

Investigating the effect of nano-silica on efficiency of the foam in enhanced oil recovery

Due to the vast production of crude oil and consequent pressure drops through the reservoirs, secondary and tertiary oil recovery processes are highly necessary to recover the trapped oil. Among the different tertiary oil recovery processes, foam injection is one of the most newly proposed methods. In this regard, in the current investigation, foam solution is prepared using formation brine, C₁₉TAB surfactant and air concomitant with nano-silica (SiO₂) as foam stabilizer and mobility controller. The measurements revealed that using the surfactant-nano SiO₂ foam solution not only leads to formation of stable foam, but also can reduce the interfacial tension mostly considered as an effective parameter for higher oil recovery. Finally, the results demonstrate that there is a good chance of reducing the mobility ratio from 1.12 for formation brine and reservoir oil to 0.845 for foam solution prepared by nanoparticles.     

Effects of compositional variations on CO2 foam under miscible conditions

Foam can mitigate the associated problems with the gas injection by reducing the mobility of the injected gas. The presence of an immiscible oleic phase can adversely affect the foam stability. Nevertheless, under miscible conditions gas and oil mix in different proportions forming a phase with a varying composition at the proximity of the displacement front. Therefore, it is important to understand how the compositional variations of the front affect the foam behavior. In this study through several core‐flood experiments under miscible condition, three different regimes were identified based on the effects of the mixed‐phase composition on CO₂ foam‐flow behavior: In Regime 1 the apparent viscosity of the in‐situ fluid was the highest and increased with increasing x_CO2. In Regime 2 the apparent viscosity increased with decreasing x_CO2. In Regime 3 the apparent viscosity of the fluid remained relatively low and insensitive to the value of x_CO2. © 2017 American Institute of Chemical Engineers AIChE J, 64: 758–764, 2018     

Experimental investigation and modelling of CO2-foam flow in heavy oil systems

In this work, the C_14-16 alpha olefin sulphonate (AOS) surfactant, octylphenol ethoxylate (TX-100), and methyl bis[Ethyl(Tallowate)]-2-hydroxyethyl ammonium methyl sulphate (VT-90) surfactant were selected as representatives of anionic, nonionic, and cationic surfactant to stabilize foam. The effects of surfactant concentration and gas/liquid injection rates on foam performance were examined by performing a series of oil-free foam flow tests by injecting CO₂ and a foaming surfactant simultaneously into sandpacks. Foam flooding was conducted as a tertiary enhanced oil recovery (EOR) method after conventional water flooding and surfactant flooding. Furthermore, a new method was proposed to determine the residual oil saturation. The foam stability in the presence and absence of heavy oil was studied by a comparative evaluation of the mobility reduction factor (F_MR) in both cases. The foam fractional flow modelling by Dholkawala and Sarma^[36] was modified based on experimental results obtained in this study. The range of the ratio of two important model parameters (C_g/C_c) at various foam qualities was determined and could be used for large-scale predictions. The results showed that during the oil-free foam displacement experiments higher foam apparent viscosities () were attained at lower gas flow rates and the maximum was attained at a total gas and liquid injection rate of 0.25 cm³/min with a gas fractional flow ratio of 0.8 for the foam in the absence of oil. The presence of oil reduced the foam mobility reduction factors (F_MR) to different degrees with F_MR-_{without oil} / F_MR-_{with oil} ranging from 4.25–13.69, indicating that the oil had a detrimental effect on the foam texture. The foam flooding successfully produced an additional 8.1–21.52 % of OOIP, which can be attributed to the combined effect of increasing the pressure gradient and oil transporting mechanisms.     

Fabrication of PEI-grafted porous polymer foam for CO2 capture

A polymer foam material with both the open-cell porous structure and the polyethylenemine (PEI)-grafted inner face was constructed for CO₂ capture. The porous poly(tert-butyl acrylate) foam was first prepared via a concentrated emulsion polymerization, and then the carboxyl groups were introduced on the interface of porous polymer after the hydrolysis reaction. Subsequently, the surface of the foam was grafted with PEI, and finally the PEI-grafted porous polymer foam designed as a CO₂ capture material was obtained. The structures of the foams were characterized by infrared spectroscopy, EDS, and SEM. The CO₂ adsorption properties were measured by adsorption/desorption cycles. As a result, the polymer foam contained a large number of amine groups (13.9 wt % N), and therefore possessed a high CO₂ adsorption capacity (5.91 mmol g⁻¹ at 40°C and 100 kPa). In addition, they also exhibited high CO₂ adsorption rate, good selectivity for CO₂-N₂ separation, and good stability according to CO₂ cyclic adsorption/desorption test. © 2019 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2019 , 136, 47844.     

Aqueous Foam Stabilized by Hydrophobic SiO2 Nanoparticles using Mixed Anionic Surfactant Systems under High-Salinity Brine Condition

A primary concern of surfactant-assisted foams in enhanced oil recovery (EOR) is the stability of the foams. In recent studies, foam stability has been successfully improved by the use of nanoparticles (NP). The adhesion energy of the NP is larger than the adsorbed surfactant molecules at the air–water interface, leading to a steric barrier to mitigate foam-film ruptures and liquid-foam coalescence. In this study, the partially hydrophobic SiO₂ nanoparticles (SiO₂-NP) were introduced to anionic mixed-surfactant systems to investigate their potential for improving the foamability and stability. An appropriate ratio of internal olefin sulfonate (C_15-18 IOS) and sodium polyethylene glycol monohexadecyl ether sulfate (C₃₂H₆₆Na₂O₅S) was selected to avoid the formation of undesirable effects such as precipitation and phase separation under high-salt conditions. The effects of the NP-stabilized foams were investigated through a static foam column experiment. The surface tension, zeta potential, bubble size, and bubble size distribution were observed. The stability of the static foam in a column test was evaluated by co-injecting the NP-surfactant mixture with air gas. The results indicate that the foam stability depends on the dispersion of NP in the bulk phase and at the water–air interface. A correlation was observed in the NP-stabilized foam that stability increased with increasing negative zeta potential values (−54.2 mv). This result also corresponds to the smallest bubble size (214 μm in diameter) and uniform size distribution pattern. The findings from this study provide insights into the viability of creating NP-surfactant interactions in surfactant-stabilized foams for oil field applications.