Enhanced heavy oil recovery through interfacial instability: A study of chemical flooding for Brintnell heavy oil

This study is aimed at developing an alkaline/surfactant-enhanced oil recovery process for heavy oil reservoirs with oil viscosities ranging from 1000 to 10,000 mPa s, through the mechanism of interfacial instability. Instead of the oil viscosity being reduced, as in thermal and solvent/gas injection processes, oil is dispersed into and transported through the water phase to production wells.Extensive emulsification tests and oil/water interfacial tension measurements were conducted to screen alkali and surfactant for the oil and the brine samples collected from Brintnell reservoir. The heavy oil/water interfacial tension could be reduced to about 7 × 10⁻² dyn/cm with the addition of a mixture of Na₂CO₃ and NaOH in the formation brine without evident dynamic effect. The oil/water interfacial tension could be further reduced to 1 × 10⁻² dyn/cm when a very low surfactant concentration (0.005-0.03 wt%) was applied to the above alkaline solution. Emulsification tests showed that in situ self-dispersion of the heavy oil into the water phase occurred when a carefully designed chemical solution was applied.A series of 21 flood tests were conducted in sandpacks to evaluate the chemical formulas obtained from screening tests for the oil. Tertiary oil recoveries of about 22-23% IOIP (32-35% ROIP) were obtained for the tests using 0.6 wt% alkaline (weight ratio of Na₂CO₃ to NaOH = 2:1) and 0.045 wt% surfactant solution in the formation brine. The sandpack flood results obtained in this project showed that a synergistic enhancement among the chemicals did occur in the tertiary recovery process through the interfacial instability mechanism.     

Investigation of silica nanoparticles grafted with sulphonated polymer for enhanced oil recovery at high temperature and high salt

Nano-fluids' application for enhanced oil recovery (EOR) has attracted noticeable attention and formed a new research area in recent years. Currently, the greatest challenge in this area is to formulate stable nano-fluids for oil reservoirs with high temperatures and salinity. To overcome the limitations of its application in high-temperature drilling, polymer-coated nanoparticles (SiO₂-PAMPS NPs) were prepared via solution polymerization of 2-acrylamide-2-methyl-1-propane sulphonic acid (AMPS) from the surface of aminopropyl-functionalized silica nanoparticles. The SiO₂-PAMPS NPs were characterized by Fourier-transform infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), scanning electron microscopy (SEM), and dynamic light scattering (DLS). The results indicated that the AMPS was successfully grafted onto the surface of silica nanoparticles, and the average diameter of SiO₂-PAMPS NPs was about 16 nm. The nano-fluids showed noticeable stability in American Petroleum Institute (API) brine (2 wt.% CaCl₂ and 8 wt.% NaCl) at 90°C beyond 46 days. When amphipathic nanoparticles were introduced to brine at 90°C, the potential of the nano-fluids in recovering oil was evaluated by investigating the interfacial tension with kerosene oil and the oil contact angle in the nano-fluids. The contact angle of the glass sheet surface before treatment was about 144°, while after SiO₂-PAMPS NPs treatment for 72 h, it became about 92°. Meanwhile, the nano-fluids showed an excellent enhancing emulsibility property, which plays a vital role in promoting the development of EOR in high-temperature and high-salt environments.     

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.     

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.     

Degradable Superhydrophilic Iron-Pillared Bentonite Doped with Polybutylene Adipate/Terephthalate Open-Cell Foam: Its Application in Dye Degradation,Removal of Heavy Metal Ions,and Oil–Water Separation

Development of industrialization has brought convenience to people's lives; however, it has also brought serious harm to the environment, where, water pollution is the most obvious. Here, a polybutylene adipate terephthalate (PBAT) open-cell foam doped with iron-pillared bentonite (IPB) is prepared by using sugar as a pore-forming agent and solution phase separation, and then combined with a solution dipping method to coat the foam surface with a polyacrylamide/SiO₂, which makes the PBAT foam superhydrophilic. The static adsorption effect of superhydrophilic IPB-doped PBAT open-cell foam on methylene blue (MB) and Cu²⁺ is studied. The adsorption isotherm fitting shows that the adsorption conforms to the Langmuir model and it has biased toward monolayer adsorption. The adsorption kinetics fitting confirms that the adsorption process is in line with the pseudo-second-order adsorption model, which is dominated by chemical adsorption. The modified PBAT open-cell foam has an adsorption effect on Cu²⁺; however, it has weak cyclic adsorption capacity. It shows a good cyclic adsorption ability for the cationic dye MB and it has >95% photodegradation efficiency of the MB after five time's cyclic adsorption. The superhydrophilicity makes the foam to have better applications in oil–water separation.     

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.     

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.     

Mechanical Properties and Flame Retardancy of Rigid Polyurethane Foams Containing SiO2 Nanospheres/Graphene Oxide Hybrid and Dimethyl Methylphosphonate

Halogen-free flame-retardant rigid polyurethane foams were prepared using the combination of SiO₂ nanospheres/graphene oxide hybrid and a phosphorus-containing flame retardant, dimethyl methylphosphonate. The flame retardancy, mechanical, and thermal properties of flame-retardant rigid polyurethane foams containing dimethyl methylphosphonate and SiO₂ nanospheres/graphene oxide were investigated. The results demonstrated that the combination of dimethyl methylphosphonate and SiO₂ nanospheres/graphene oxide enhanced flame retardant and mechanical properties of rigid polyurethane foam greatly compared with pure rigid polyurethane foam and dimethyl methylphosphonate-modified foam. Morphological study indicated that the partial substitution of dimethyl methylphosphonate with SiO₂ nanospheres/graphene oxide led to smaller cell sizes and more uniform cell sizes of dimethyl methylphosphonate-modified rigid polyurethane foams.     

New method for the determination of surfactant solubility and partitioning between CO2 and brine

A novel method is presented for measuring solubility in supercritical CO₂ (scCO₂), which can be used in conjunction with traditional cloud point measurements to obtain information directly on the soluble portion of a given sample and, ultimately, a much more informative data set. In this method, surfactant from a known amount of CO₂ solution was transferred into an aqueous solution and the surfactant concentration of the aqueous solution was measured directly by HPLC (high-performance liquid chromatography). In this work, the partitioning of a series of 2-ethylhexanol (2-EH) alkoxylate surfactants among an aqueous phase (water or brine) and scCO₂ as a function of electrolyte concentration, temperature, and pressure was also investigated. Surfactant partition coefficient was determined based on the reduction of HPLC measured surfactant concentration in the aqueous phase due to surfactant partitioning into CO₂. An understanding of surfactant partitioning between brine and scCO₂ is particularly important in the design of CO₂ foam processes, particularly for surfactant stabilized foam in subsurface systems, where it can affect surfactant transport and foam propagation. In general, the solubility in scCO₂ increased with pressure and decreased with temperature. The partitioning of the surfactants between CO₂ and water phases was almost proportional to pressure, and decreased as temperature increased, where the latter held more sensitivity. The partition coefficient was very sensitive to surfactant formula. For the 2-EH-PO5-EO_x series, the partition coefficient between scCO₂ and the aqueous phase increased with decreasing EO content.     

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.     

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.     

Control interfacial microstructure and improve mechanical properties of TC4-SiO2f/SiO2 joint by AgCuTi with Cu foam as interlayer

Brazing SiO_2f/SiO₂ ceramics to TC4 is often associated with the problems of excessive Ti from the dissolution of TC4 and high residual stress, which results in low-strength joints. To overcome these problems, here we put forward an effective method by introducing Cu foam as interlayer to obtain high-strength joints of SiO_2f/SiO₂-TC4. The effect of Cu foam on the microstructure and mechanical properties of brazed joints was investigated. Cu foam can consume Ti from TC4 and inhibit forming too many brittle compounds at the SiO_2f/SiO₂ side. Furthermore, Cu foam can react with Ti, forming the dispersed homogeneous distribution of fine-grained Ti-Cu compounds in the brazing seam, due to its unique 3D porous structure. The formation and distribution of fine-grained Ti-Cu compounds at the brazing seam could significantly help to reduce the residual stress and reinforce the mechanical properties of the joint. Maximum shear strength of 59.6 MPa is approached.     

A new method of preparing superabsorbent PVF porous foam through the simultaneous acidification of water glass solution–aspect of environmental protection

To reduce the wastewater pollution problem, silica particles that have resulted from simultaneous sulfuric acidification of water glass solution serve as the pore‐forming agent for preparing superabsorbent PVF/SiO₂ foam in this study. This is a departure from the traditional porous PVF/starch foam's manufacture method. The pore structure of PVF/SiO₂ foam is very different from that of PVF/starch foam. The effect of the concentration of these pore‐forming agents on the pore structure, mechanical modulus, and water adsorption capacity of PVF/starch and PVF/SiO₂ foams are investigated in this study. © 2013 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2014 , 131, 39894.     

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.     

Mechanistic simulation of continuous gas injection period during surfactant-alternating-gas (SAG) processes using foam catastrophe theory

The use of foam for mobility control is a promising means to improve sweep efficiency in subsurface applications such as improved/enhanced oil recovery and aquifer remediation. Foam can be introduced into geological formations by injecting gas and surfactant solutions simultaneously or alternatively. Alternating gas and surfactant solutions, which is often referred to as surfactant-alternating-gas (SAG) processes, is known to effectively create fine-textured strong foams in situ by repeating drainage and imbibition processes. Recent studies show that foam rheology in porous media can be characterized by foam catastrophe theory which exhibits three foam states (weak-foam, strong-foam, and intermediate states) and two strong-foam regimes (high-quality and low-quality regimes).Using both mechanistic foam simulation technique and fractional flow analysis which are consistent with foam catastrophe theory, this study aims to understand the fundamentals of dynamic foam displacement during gas injection in SAG processes. The results revealed some important findings: (1) the complicated mechanistic foam fractional flow curves (f_w vs. S_w) with both positive and negative slopes require a new way to solve the problem analytically rather than the typical method of constructing a tangent line from the initial condition; (2) none of the conventional mechanistic foam simulation and fractional flow analysis can fully capture sharply changing dynamic foam behavior at the leading edge of gas bank, which can be overcome by the pressure-modification procedure suggested in this study; (3) four foam model parameters (?p_o, n, C_g/C_c, and C_f) can be determined systematically by using an S-shaped foam catastrophe curve, a two flow-regime map, and a coreflood experiment showing the onset of foam generation; and (4) at given input data set of foam simulation parameters, the inlet effect which explains a delay in strong-foam propagation near the core face is scaled by the system length, and therefore the change in system length requires a new set of individual lamella creation and coalescence parameters (C_g and C_c).     

Superhydrophobic and oleophilic micro‐nano hierarchical Pd‐decorated SiO2 layers

This paper reports a novel fluorinated micro‐nano hierarchical Pd‐decorated SiO₂ structure (hereafter called Pd/SiO₂), which was formed by the deposition of Pd nanoparticles (NPs) on SiO₂ microspheres. The SiO₂ layers with microscale roughness were fabricated by electrospraying a solution prepared using the sol‐gel process. Subsequently, the Pd NPs were deposited using an ultraviolet reduction process. The resulting surfaces exhibited a micro‐nano hierarchical morphology. After fluorination, the micro‐nano hierarchical surface exhibited outstanding water repellency with a water contact angle (WCA) of 170° and a sliding angle <5°, indicating excellent superhydrophobic properties. The layers exhibited good long‐term durability and excellent ultraviolet resistance. Interestingly, the surface was oleophilic (CA of oil ~10°). These results show the potential of employing superhydrophobic fluorinated Pd/SiO₂ layers in smart devices, such as self‐cleanable surfaces and intelligent water/oil separation systems.     

Recycling of waste lubricant oil into chemical feedstock or fuel oil over supported iron oxide catalysts

The recycling of waste lubricant oil from automobile industry was found to be best alternative to incineration. Silica (SiO₂), alumina (Al₂O₃), silica-alumina (SiO₂-Al₂O₃) supported iron oxide (10 wt% Fe) catalysts were prepared by wet impregnation method and used for the desulphurisation of waste lubricant oil into fuel oil. The extent of sulphur removal increases in the sequence of Fe/SiO₂-Al₂O₃<Fe/Al₂O₃<Fe/SiO₂ and this might be due to the presence of smaller crystalline size (7.4 nm) of Fe₂O₃ in Fe/SiO₂ catalyst. X-ray diffraction results suggest the presence of iron sulphide in the used catalyst. Gas chromatography with thermal conductivity detector analysis confirms the presence of H₂S in gaseous products. In addition, Fe/SiO₂ catalyst facilitated the formation of lower hydrocarbons by cracking higher hydrocarbons (≈C₄₀) present in waste lubricant oil.     

Preparation of poly(acrylamide‐co‐acrylic acid)/silica nanocomposite microspheres and their performance as a plugging material for deep profile control

In this work, poly(acrylamide‐co‐acrylic acid)/silica [poly(AM‐co‐AA)/SiO₂] microspheres were prepared by inverse phase suspension polymerization in the presence of γ‐3‐(trimethoxysilyl) propyl methacrylate (or 3‐methacryloxypropyltrimethoxysilane) modified SiO₂. The effects of SiO₂ nanoparticles on tuning morphology and properties of the nanocomposite microspheres were studied. Plugging ability and oil displacement performance were also systematically investigated by single‐ and double‐tube sand pack models. The results showed that SiO₂ nanoparticles can effectively adjust surface smoothness, swelling behavior, and thermal stability of the nanocomposite microspheres. Compared with pure copolymer microspheres, these nanocomposite microspheres also displayed better salt tolerance and shear resistance. Such multifunctional nanocomposite microspheres can provide effective plugging in the high‐permeability channels and can also achieve deep profile control. The highest plugging rate can be 86.11% and the oil recovery for low‐permeability tube was enhanced by 19.69%. This research will provide a candidate material for the further enhanced oil recovery (EOR) research and supply the theoretical support for profile control system in field application. © 2017 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2017 , 134, 45502.     

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.     

Impact of Divalent Ions on Heavy Oil Recovery by in situ Emulsification

Many reservoir formation brines are characterized by high salinity and contain high concentrations of divalent ions such as calcium, magnesium, and potassium. These challenging conditions can render the surfactants ineffective during chemical flooding for enhanced heavy oil recovery. Various brine types can have an impact on the stability of emulsions generated with chemicals as chemicals have various resistant levels toward hard divalent ions and salinities. To investigate the impact of brine hardness on heavy oil-in-water emulsion stability, glass tube experiments, microscopic visualization and sandpack flooding experiments, and Hele-Shaw visualization experiments were conducted in this study under low-salinity/hard-brine, high-salinity/hard-brine conditions using commercial chemicals, which are designed for specific reservoir brine conditions. Recovery results demonstrated that complex colloidal solution introduced in the previous study with silica and Dodecyltrimethylammonium bromide (DTAB) along with screened chemicals from glass tube tests in this study can enhance heavy oil recovery significantly with an addition of low concentration of xanthan gum (Lee and Babadagli 2018). The results confirmed the robustness of the complex colloidal solution formula to enhance oil recovery with low concentration of polymer under any reservoir brine conditions. The study also demonstrates the potential of polymer as an emulsion stabilization additive for enhanced heavy oil recovery by in situ emulsion generation. Polymer effects seemed to be particularly dominant under the low-salinity conditions than high-salinity conditions.