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.     

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.     

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.     

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.     

Thermo- and CO2-triggered swelling polymer microgels for reducing water-cut during CO2 flooding

CO₂ has been widely used in the process of enhanced oil recovery (EOR) over decades. However, the heterogeneity of oil reservoirs renders CO₂ to flow preferentially into highly permeable zones, leaving tight areas unswept with oil unrecovered in these areas. While conventional water-swelling gels were used for blocking the “channeling” path, most of them experience the risks of shrinkage under high temperature and CO₂-induced acidic environment. Here, we developed double swelling smart polymer microgels (SPMs) triggered by both heat and CO₂. Such SPMs were prepared by copolymerization of acrylamide (AAm) in combination with N,N-2-(dimethylamino)ethyl methacrylate (DMAEMA) and [2-(methacryloyloxy) ethyl]dimethyl-(3-sulfopropyl) ammonium hydroxide (SBMA), and with N,N′-methylene bisacrylamide (MBA) as the crosslinker. These SPMs swell when temperature is higher than 65 °C or in the presence of CO₂, with an ameliorative salinity tolerance ability. Artificial sand pack flooding carried by SMPs at 65 °C showed an elevated plugging efficiency at around 97% under a simulated pressurization at 5 MPa, proposing a valid candidate for future EOR applications during CO₂ flooding. © 2019 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2019 , 136, 48305.     

Effect of oil viscosity on recovery processes in relation to foam flooding

Laboratory experiments were conducted to determine the effect of oil viscosity on the oil-recovery efficiency in porous media. The pure surfactants (i.e., sodium dodecyl sulfate and various alkyl alcohols) were selected to correlate the molecular and surface properties of foaming solutions with viscosity, and the recovery of oil. Oil-displacement efficiency was measured by water, surfactant-solution and foam-flooding processes, which included 2 types of foams (i.e., air foam and steam foam). A significant increase in heavy-oil recovery was observed by steam foam flooding compared with that by air foam flooding, whereas for light oils, the steam foam and air foam produced about the same oil recovery. An attempt was made to correlate the chain-length compatibility with the surface properties of the foaming agents and oil-recovery efficiency in porous media. For mixed foaming systems (C₁₂ SO₄ Na + C_n H_2n+1 OH), a minimum in surface tension, a maximum in surface viscosity, a minimum in bubble size and a maximum in oil recovery were observed when both components of the foaming system had the same chain length. These results were explained on the basis of thermal motions (i.e., vibrational, rotational and oscillational) and the molecular packing of surfactants at the gas-liquid interface. The effects of chain-length compatibility and the surface properties of mixed surfactants are relevant to the design of surfactant formulations for oil recovery under given reservoir conditions.     

Carbon dioxide flooding for enhanced oil recovery: Promise and problems

Of the enhanced oil recovery methods currently being considered for application to many of the nation’s older oil fields, carbon dioxide flooding may offer the largest potential for additional oil recovery. The physical mechanisms by which CO₂ contacts and mobilizes crude oil are reviewed. Influence on the displacement process of factors such as the phase behavior of CO₂-crude oil mixtures, swelling of oil by dissolved CO₂, and reduction of oil viscosity are considered. Adverse effects of the viscous instability which occurs when very low viscosity CO₂ displaces the more viscous oil and water are dicussed. Advantages and disadvantages of three potential methods for controlling the mobility of CO₂ are reviewed: thickening CO₂ with polymeric additives, reduction of CO₂ mobility by high water saturations, and use of surfactants to generate foam-like emulsions of water and CO₂. Field experience to date and the recent surge in field activity are discussed. Finally, a brief assessment of the future of CO₂ flooding research and practice is offered.     

Synthesis of an Alkyl Polyoxyethylene Ether Sulfonate Surfactant and Its Application in Surfactant Flooding

Surfactant flooding as a potential enhanced oil‐recovery technology in a high‐temperature and high‐salinity oil reservoir after water flooding has attracted extensive attention. In this study, the synthesis of an alkyl alcohol polyoxyethylene ether sulfonate surfactant (C₁₂EO₇S) with dodecyl alcohol polyoxyethylene ether and sodium 2‐chloroethanesulfonate monohydrate, and its adaptability in surfactant flooding were investigated. The fundamental parameters of C₁₂EO₇S were obtained via surface tension measurement. And the ability to reduce oil–water interfacial tension (IFT), wettability alteration, emulsification, and adsorption was determined. The results illustrated that IFT could be reduced to 10^?3 mN m^?1 at high temperature and high salinity without additional additives, and C₁₂EO₇S exhibited benign wettability alternate ability, and emulsifying ability. Furthermore, the oil‐displacement experiments showed that C₁₂EO₇S solution could remarkably enhance oil recovery by 16.19% without adding any additives.     

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.     

Molecular dynamics simulation of the synergistic effect of a compound surfactant on the stability of CO2 oil-based foam

It is of great significance to study the stability of foams in the petroleum industry. Therefore, the stability mechanism of Span 20, the fluorinated surfactant FCO-80 and their mixture FS in a CO₂ oil-based foam system were studied by molecular simulation. The sandwich model of CO₂ oil-based foam was constructed to reveal the stability of the foam system from the microscopic perspective. The result shows that under the synergistic effect of Span 20 and FCO-80, the oil–CO₂ distance of the FS foam system and the coordination number of oil molecules are larger than those of Span 20 and FCO-80 foam system. In FS foam system, the diffusion coefficients of CO₂ molecules are small, and the surface tension is reduced, which can improve the stability of foam. The results can supplement previous experimental results on the stability of oil-based foam.     

Parameter estimation in multiple contact CO2 miscibility simulation with uncertain experimental core flooding data

CO₂ flooding, which is an efficient method of enhanced oil recovery, is a very complicated process involving phase behavior. To understand the performance of CO₂ flooding and provide accurate data for designing reservoir development, a comprehensive investigation of the phase behavior of CO₂ miscible flooding and an accurate compositional reservoir simulation needs to be conducted. In PVT modeling, an effective and more physically reasonable equation of state model was achieved and the feasibility of CO₂ miscible flooding was determined by multiple contact minimum miscibility pressure (MCMMP) calculation. Furthermore, compositional reservoir simulation studies for predicting CO₂ miscible performance were designed and constructed with core flooding data. By matching with laboratory core flooding data, we can estimate parameters with uncertainty. The objective of this study was to find a work flow for parameter estimation in CO₂ miscible flooding process that can be used to design and optimize field CO₂ miscible floods.     

空气泡沫驱驱油机理与实验研究

针对传统聚合物驱、三元复合驱等驱油体系在中后期油田开采中采油效率不高的问题,提出一种高效空气泡沫驱驱油技术。为验证高效泡沫驱的驱油效果,以延长油田1#地质条件为背景,探讨不同起泡剂浓度、矿化度下对空气泡沫驱的性能影响,从而筛选出空气泡沫驱的最优综合性能,通过驱替实验,对高效泡沫驱驱油机理进行观察。最后通过封堵能力评价验证了空气泡沫驱的性能与驱油机理。     

Reducing heavy oil carbon footprint and enhancing production through CO2 injection

The world's dependence on heavy oil production is on the rise as the existing conventional oil reservoirs mature and their production decline. Compared to conventional oil, heavy oil is much more viscous and hence its production is much more difficult. Various thermal methods and particularly steam injection are applied in the field to heat up the oil and to help with its flow and production. However, the thermal recovery methods are very energy intensive with significant negative environmental impact including the production of large quantities of CO₂. Alternative non-thermal recovery methods are therefore needed to allow heavy oil production by more environmentally acceptable methods. Injection of CO₂ in heavy oil reservoirs increases oil recovery while eliminating negative impacts of thermal methods.In this paper we present the results of a series of micromodel and coreflood experiments carried out to investigate the performance of CO₂ injection in an extra-heavy crude oil as a method for enhancing heavy oil recovery and at the same time storing CO₂. We reveal the pore-scale interactions of CO₂-heavy oil-water and quantify the volume of CO₂ which can be stored in these reservoirs.The results demonstrate that CO₂ injection can provide an effective and environmentally friendly alternative method for heavy oil recovery. CO₂ injection can be used independently or in conjunction with thermal recovery methods to reduce their carbon footprint by injecting the CO₂ generated during steam generation in the reservoirs rather than releasing it in the atmosphere.     

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.     

NOx storage behavior and sulfur-resisting performance of the third-generation NSR catalysts Pt/K/TiO2–ZrO2

The NO_x storage and reduction (NSR) catalysts Pt/K/TiO₂–ZrO₂ were prepared by an impregnation method. The techniques of XRD, NH₃-TPD, CO₂-TPD, H₂-TPR and in situDRIFTS were employed to investigate their NO_x storage behavior and sulfur-resisting performance. It is revealed that the storage capacity and sulfur-resisting ability of these catalysts depend strongly on the calcination temperature of the support. The catalyst with theist support calcined at 500 °C, exhibits the largest specific surface area but the lowest storage capacity. With increasing calcination temperature, the NO_x storage capacity of the catalyst improves greatly, but the sulfur-resisting ability of the catalyst decreases. In situ DRIFTS results show that free nitrate species and bulk sulfates are the main storage and sulfation species, respectively, for all the catalysts studied. The CO₂-TPD results indicate that the decomposition performance of K₂CO₃ is largely determined by the surface property of the TiO₂–ZrO₂ support. The interaction between the surface hydroxyl of the support and K₂CO₃ promotes the decomposition of K₂CO₃ to form –OK groups bound to the support, leading to low NO_x storage capacity but high sulfur-resisting ability, while the interaction between the highly dispersed K₂CO₃ species and Lewis acid sites gives rise to high NO_x storage capacity but decreased sulfur-resisting ability. The optimal calcination temperature of TiO₂–ZrO₂ support is 650 °C.     

泡沫复合驱配方ZS-23的研究

泡沫驱作为一项重要的三次采油技术,在降低气油比、增加原油产量、提高波及效率等诸多方面具有很大的发展潜力。对ZS系列泡沫复合驱配方进行了探索性研究,使用Waring Blender法对泡沫复合驱配方的发泡能力和稳定性进行了检测,通过实验筛选出发泡性能好、稳定性强的泡沫复合驱配方。在矿化度NaCl>5 000 mg/L、CaCl2>3 000 mg/L条件下,表现最为优异的配方为ZS-23,在常温(20℃)时,发泡体积达到880 mL,析液半衰期5.3 h以上,加盐后发泡体积达到820 mL,析液半衰期3.5 h以上,均远远好于一般常见的发泡剂。     

Optimization of in-situ combustion processes: A parameter space study towards reducing the CO2 emissions

Enhanced oil recovery (EOR) through in-situ combustion (ISC) is a process that utilizes a fraction of the oil in-place as fuel in order to upgrade and displace the hydrocarbons in heavy oil reservoirs. In ISC processes, air is injected into a heated section of the reservoir. Upon reaching a threshold temperature, the oxygen in the injected air reacts with the oil in-place and generates heat, a lighter oil fraction, as well as steam and other gaseous reaction products, primarily CO₂, which help drive the upgraded oil (lighter fraction) towards the production wells. ISC processes can, as a result, be highly efficient but at the same time produce significant amounts of CO₂, a potent greenhouse gas. In this paper the emphasis is on developing an ISC process with significantly reduced CO₂ emissions. The process involves the capture and re-injection of CO₂ into the formation. We find that, in addition to reducing the CO₂ emissions, this novel process also shows improved oil recovery rates relative to conventional ISC without CO₂ capture and recycle. We observe, for example, increases in the oil recovery of ∼33% for a fixed time of operation when comparing the ISC process with CO₂ recycle against the conventional ISC process. In addition, at the time when 80% of the total oil in-place has been produced, the CO₂ emissions are consistently lowered by 18–22% when CO₂ is recycled back into the formation. This study analyzes the characteristics and dynamics of the process and explores the effect of the relevant process parameters. For a wide range of Peclet and Damköhler numbers as well as initial saturations, favorable trends induced by CO₂ recycling are observed.     

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.     

Biodegradation of heavy oil by fungal extracellular enzymes from Aspergillus spp. shows potential to enhance oil recovery

Microbial enhanced oil recovery makes a substantial contribution to the recovery of heavy oils; however, most methods use bacteria, with less attention paid to the potential of fungi. In this study, we investigated the efficiency of fungal extracellular enzymes in biotransformation of heavy oil fractions into light compounds. Two Aspergillus isolates (A. terreus and A. nidulans) with the ability to biodegrade heavy oil were isolated from bitumen. The extracellular enzymes from these Aspergillus isolates exhibited dehydrogenase and catechol 2,3-dioxygenase activities. The biodegradation of heavy oil was coupled with abundant production of gases, mainly CO₂ and H₂. Gas chromatography analysis revealed a redistribution of n-alkanes in heavy oil after treatment with crude enzyme extracts, which resulted in an increase in individual n-alkanes. The viscosity of heavy oil was decreased considerably by enzymatic degradation. These results demonstrate the potential of fungal extracellular enzymes from Aspergillus spp. for applications in enhanced heavy oil recovery.     

Preparation of open‐cell foams from polymer blends by supercritical CO2 and their efficient oil‐absorbing performance

This letter reports on the hydrophobicity and oleophilicity of open‐cell foams from polymer blends prepared by supercritical CO₂. A typical bulk density of the foam is measured to be 0.05 g/cm³. The contact angle of the foam with water is determined to be 139.2°. The foam can selectively absorb the diesel from water with the uptake capacity of 17.0 g/g. The foams are technologically promising for application of oil spill cleanup. © 2016 American Institute of Chemical Engineers AIChE J, 62: 4182–4185, 2016