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Improved oil recovery in carbonate rocks through modified injection brine has been investigated extensively in recent years. Examples include low salinity waterflooding and surfactant injection for the purpose of residual oil reduction. Polymer addition to injection water for improvement of sweep efficiency enjoys field success. The effect of low salinity waterflooding is often marginal and it may even decrease recovery compared to seawater flooding. Polymer and surfactant injection are often effective (except at very high salinities and temperatures) but concentrations in the range of 5000 to 10000 ppm may make the processes expensive. We have recently suggested the idea of ultra-low concentration of surfactants at 100 ppm to decrease residual oil saturation from increased brine-oil interfacial elasticity. In this work, we investigate the synergistic effects of polymer injection for sweep efficiency and the surfactant for interfacial elasticity modification. The combined formulation achieves both sweep efficiency and residual oil reduction. A series of coreflood tests is performed on a carbonate rock using three crude oils and various injection brines: seawater and formation water with added surfactant and polymer. Both the surfactant and polymer are found to improve recovery at breakthrough via increase in oil-brine interfacial elasticity and injection brine viscosification, respectively. The synergy of surfactant and polymer mixed with seawater leads to higher viscosity and higher oil recovery. The overall oil recovery is found to be a strong function of oil-brine interfacial viscoelasticity with and without the surfactant and polymer in sea water and connate water injection.

Nanoparticles have improved a surfactant's ability to create long-lasting foam. Recent studies have widely recommended the use of silica nanoparticles to enhance foam stability. This paper presents an experimental investigation of a new and highly effective Alpha Olefin Sulfonate (AOS)-multiwalled carbon nanotube (MWCNT) system for mobility control during gas EOR operations. The new AOS-MWCNT system was evaluated for its foam stability at 150°F using a high-pressure view cell. The MWCNT was obtained as solid particles of aspect ratio up to 100 and silica nanoparticles of median size 118 nm. The foam system was optimized for its maximum half-life by varying the concentration of the AOS and the nanotube from 0.2-1% and 250-1,000 ppm, respectively. Compatibility testing with salts were done as well. Coreflood experiments with 1.5 in. diameter and 6 in. long Berea sandstone cores were run to calculate the mobility reduction factor at 150°F. Nitrogen foam was injected into the core at 80% foam quality in the tertiary recovery mode and the pressure drop across the core was measured. The formation brine had a salinity of 5 wt% NaCl and the foaming solutions were prepared with 2 wt% NaCl. The optimal concentrations of the AOS solution and the nanotubes for maximum foam stability were determined to be 0.5% and 500 ppm, respectively. The optimized AOS-MWCNT system yielded 70% greater nitrogen foam half-life (32 minutes) than an optimized AOS-silica system at 150°F. The foam half-life of a standalone 0.5% AOS solution was 7 minutes. In presence of crude oil, the foam half-life decreased for all the tested systems. Coreflood experiments at 150°F showed a significant increase in the mobility reduction factor when the new AOS-MWCNT system was used as the foamer instead of standalone AOS or AOS-silica system. The new foaming system was stable through the duration of the experiment, yielding foam in the effluent samples. There was no formation damage observed. Salt tolerance for the MWCNT nanofluid was higher than the silica nanofluid. Foam needs to be stable for long periods of time to ensure effective mobility control during gas injection for EOR. This paper investigates a new highly effective AOS-multiwalled carbon nanotube system that outperforms the AOS-silica foaming systems in terms of foam stability and mobility control at 150°F.

Surfactants in literature have been reviewed and evaluated as foaming agents, but few of them fit our harsh operational and reservoir conditions. Therefore, surfactant formulations were tuned with guide of micelle electrostatic model and Winsor type phase behavior. The novel formulations are compatible with high temperature (94 ℃) and wide salinity (50 - 290 g/L). Moreover, one of the formulations can generate relatively weak foam at high residual oil saturation (Sor), but strong foam at low Sor. This auto-selection of foam by Sor allows to block the swept and clean zone, but not lockdown the virgin oil reserve and flooding front. At the end of foam flooding, almost 100% residual oil was recovered. Additionally, the operational conditions, such as injecting brines, anti-corrosions, demulsifiers, etc., are often subjected to be changed. Therefore, a rapid bulk-foam test is proposed to re-verify the compatibility of the formulation with the new operational condition.

Achieving mobility control of steam in porous media has been approached by the implementation of foaming surfactant additives; however, foam generated with surfactants lack stability at high temperatures (≥ 200 °C). In this study, a nanofluid was formulated for steam co-injection to address common issues with surfactants as steam additives. The nanofluids were formulated using synergistic interaction of nanoparticles and surfactants (both readily available) to address thermal stability, and foam stability at the conditions encountered in thermal enhanced oil recovery processes such as steam assisted gravity drainage. Zeta potential analysis, static tests, and high temperature aging tests were performed to obtain the ideal mixture of nanoparticles and surfactants. A steam/foam core flooding apparatus was used to evaluate the mobility reduction of nanofluids using multiple differential pressure transmitters situated along the length of a 40 cmsand pack to confirm foam propagation. The tests were first conducted at 200 °C with nitrogen as a non-condensable gas carrier. Upon confirming nanofluid mobility reduction characteristics at 200 °C with gas, a successful nanofluid was co-injected with superheated steam at backpressure corresponding to a saturation temperature of 200 °C inside an oven with that set point. Mobility reduction characteristics were obtained for each formulation by normalizing the differential pressure of additive multiphase flow to their respective baselines. Statictests and high-temperature core floods demonstrated a strong synergy between appropriate combinations of surfactants and nanoparticles.None of thesurfactants and nanoparticlesyielded mobility reduction when used on their own; however, when selected according to a design basis, nanoparticle/surfactant mixtures exhibit strong mobility control with steam as well as hot gas. The foam produced in the porous media was held in a visual cellat 150 °C for 24 h with no loss in foam height. Furthermore, foam generated with the nanoparticle-surfactant hybrid remained stable in static tests in the presence of heavy crude oil for more than one week. The primary novelty of this study is the ability to use less exotic surfactants and nanoparticles as steam mobility control agents, increased foam stability in the presence of oil, and demonstrable synergy between commodity molecules (i.e., surfactant) and nanoparticles at steam flooding conditions. The successful additive mixture was developed with scalability in mind such that manufacturing will not hinder the feasibility of scale-up for industrial use.

Two major applications of injecting dense carbon dioxide (CO2) into the petroleum reservoirs are enhanced oil recovery and sequester CO2 underground. For enhanced oil recovery applications, CO2 has low miscibility pressure causing the swelling of crude oil and reducing its viscosity therefore improving the macroscopic sweep process. However, the low viscosity of injected CO2 compared with the reservoir fluids causes the fingering of CO2, which may lead to bypassing huge amount of oil, early breakthrough of CO2, and increasing the gas to oil ratio (GOR). The use of direct thickeners, such as polymers, is one of the techniques used to increase the CO2 viscosity. Nevertheless, the solubility of polymers in CO2 and the high cost of soluble polymers are the main challenges facing this technique. In this study, a novel, soluble, and cost-effective thickener is proposed to directly increase the CO2 viscosity. In this study, a PVT high pressure and high temperature (HPHT) apparatus was used to evaluate the compatibility and the solubility of the thickener in dense CO2. Also, a custom designed apparatus was used to measure the viscosity of dense CO2 in the presence of the thickener at different conditions. The assessment was conducted at different experimental pressures, temperatures, and thickener concentrations. The effect of pressure on the solubility of the thickener in CO2 and on the measured viscosity of CO2 was evaluated at 1500, 2000, 2500, and 3000 psi. Also, the influence of temperature was evaluated at 25 and 50°C. Moreover, the concentrations used to study the effect of thickener concentration on the measured viscosity of CO2 ranged between 0.10-2 %. The results from laboratory experiments clearly demonstrated that the addition of the thickener at certain conditions can significantly impact the dense CO2 viscosity. The results revealed that there must be a minimum pressure at which the thickener dissolves in the dense CO2. The solubility of the thickener can occur when the CO2 is either in the liquid or supercritical phase. The results also pointed out that the CO2 viscosity increased as the pressure increased. The increase of CO2 pressure can significantly impact the solubility of the thickener in the dense CO2 and consequently the CO2 viscosity. The increase of the thickener concentration also had a significant impact on the measured CO2 viscosity. The results showed that the CO2 viscosity increased with the thickener concentration. The CO2 viscosity increased 100 to 1200 -fold as a result of adding the thickener depending on the experimental conditions

Waterflood in low permeability carbonate reservoirs (

The major challenge in enhanced oil recovery (EOR) by gas injection is poor volumetric sweep efficiency, mainly due to the high gas mobility and reservoir heterogeneity. Injecting gas as a foam increases sweep efficiency, but maintaining foam stability within the reservoir remains a challenge. This research evaluates the synergistic interaction of one type of nanoparticle and a surfactant to increase foam stability, using the concentration ratio of the two components to tune the affinity of the nanoparticle for the gas/liquid interface. We test the capability of the synergistic two-component system to stabilize methane foam and compare it with foam stabilized by surfactants only. A key distinction is the foam stability upon contact with oil, and we explain the observations in static and dynamic conditions.Foam stability was measured both in static (foam height) and dynamic (flow through porous media) conditions. In the static test, foam is generated by the shaking method, and foam texture (bubble size and shape) and the decay of foam height with time are indicators of foam stability. To test static stability in presence of oil, heavy oil is injected into the foam-liquid interface. In dynamic test, foam is pre-generated before flowing at elevated pressures into sandpacks containing various oil saturations. Normalized pressure gradient, and apparent viscosity are the indicators of foam stability and effectiveness for improving oil recovery.The extent to which nanoparticles are covered with surfactant governs the foam stability both in static and dynamic conditions. Static foam is stable in the presence of oil only if the nanoparticles are partially covered by the surfactant. In the dynamic test, foam stabilized with the only surfactant collapses in the porous media when oil is present. Nanoparticles alone could not generate foam regardless of the presence of oil, but foam stabilized with nanoparticles partially covered by surfactant is stable in the presence of both residual and initial oil. In both static and dynamic conditions, nanoparticles completely covered with a bilayer of surfactant do not stabilize foam in the presence of oil. Partially covered nanoparticles foam also demonstrated salt tolerance in both static and dynamic test. Thus at appropriate surface coverage, the combination of nanoparticles and surfactant is more effective than either stabilizer alone.The result shows that surfactant and nanoparticles interaction is important in foam stability in the porous media with oil. In particular, this interaction is synergistic at certain coverage. This type of synergy can provide much more robust mobility control for EOR processes involving gas injection.

Foam processes aim to improve the efficiency of gas-based injection methods through gases mobility control. They have been successfully applied in various EOR contexts: CCUS through CO2-EOR, steam injection for heavy oil reservoirs, and also in fractured reservoirs. The success of such processes depends on multiple factors, among which the interactions between the surfactants, the oil and the rock, play a key role. The purpose of this study is to provide initial answers by focusing on the influence of wettability and oil saturation on the behavior of CO2-foam flows.A new coreflooding set-up is designed for ‘mesoscopic’ cores (2.5 cm diameter) in order to conduct foam formulation screening and perform faster foam injection tests at reservoir conditions (up to 200 bar and 60 °C). This set-up was first validated by repeating experiments performed previously on classical corefloods with 4 cm diameter cores. Similar results in terms of mobility reduction were obtained for the same operating conditions with a considerable reduction of test duration.All experiments were performed with Clashach sandstones cores having approximatively 16 % porosity and 600 mD permeability. Two gas compositions have been studied: (1) a dense supercritical CO2 (density of 638 kg/m3 at P = 160 bar, T = 60°C) and (2) a non-dense gas mixture of CO2 and CH4. For each gas composition, four foam injection tests were carried out: two on water-wet rock samples, two others on crude-aged core samples, and for both in the absence and in presence of oil. Anionic surfactant formulations and gas were co-injected with a gas fraction of 0.7. Foam rheology was assessed by measuring foam apparent viscosity through a scan of interstitial velocities.All the tests performed in dense conditions have highlighted the generation of strong foams, which present shear-thinning rheological behavior; the apparent viscosity decreases as a power law of the interstitial velocity. An influence of the wettability is observed on the foam apparent viscosity, which drops off by 30 % in altered wettability rock samples. When samples were originally saturated with oil at Swi, the level of apparent viscosity remains globally unchanged but the kinetics of the initial formation of the foam is slower with oil than without.Foam flooding experiments are sometimes carried out simply in the presence of oil without taking into account the influence of wettability, which appears to be as important, if not more, than the oil saturation itself. These results will hopely provide some guidance for future foam studies and raise awareness on the importance of these parameters.

Enhanced oil recovery (EOR) from heavy oil reservoirs is challenging. The higher viscosity of oil in such reservoirs, add more challenges and severe the difficulties during any EOR method (i.e. high mobility ratio, inadequate sweep, reservoir heterogeneity) compared to that of EOR from light oil reservoirs. Foam has gained interest as one of the EOR methods especially for challenging and heterogeneous reservoirs containing light oil. However, the foam and especially polymer enhanced foam (PEF) potential for heavy oil recovery is less studied. The current study aims to evaluate the performance of CO2 foam and CO2 PEF during heavy oil recovery from both unconsolidated (i.e. sandpack) and consolidate (rock sample) porous media with the help of fluid flow experiments. The injection pressure profile, oil recovery, and CO2 gas production were monitored and recorded to analyze and compare the performance of CO2 foam and PEF for heavy oil recovery. A visual sandpack made of glass column and a core-flood system capable of measuring the pressure at different sections of the core were used in this study. Homogenous and fractured sandstone core samples, as well as a fractured carbonate core sample, were selected for the core-flood study. Static stability results revealed slower liquid drainage and collapse rates for PEF compared to that of foam even in the presence of heavy crude oil. The addition of polymer significantly improved the performance of CO2 foam flooding during heavy oil recovery in dynamic experiments. This result was inferred from faster propagation rate, higher dynamic stability, and higher oil recovery of CO2 PEF over CO2 foam injection. Moreover, the visual analysis demonstrated more stable frontal displacement and higher sweep efficiency of PEF compared to the conventional foam flooding. In the fractured porous media, additional heavy oil recovery was obtained by liquid diversion into the matrix area rather than gas diversion inferred from pressure profile and gas production data. The results obtained from this study show that CO2 PEF could significantly improve the heavy oil recovery and CO2 sequestration, especially in homogeneous porous media.

This paper investigates CO2-foam stabilized with nanoparticles (NP) as an enhanced oil recovery (EOR) agent in carbonate reservoirs with high temperature and salt content. Under these conditions surfactants, widely used to stabilize foams, becomes unstable and will not generate strong foam. Our objective is to use NP as a stabilizing agent for surfactant based foam through an integrated process where the surfactants generate foam and the NP stabilizes the foam. Aqueous NP solutions (1500 ppm) were injected through porous media at high temperature (120 °C) to evaluate solution stability for a range of brine salinities, pH and resident times. Stable solutions were subsequently co-injected with supercritical CO2 to create foam and increase the apparent viscosity of CO2. High temperature and salinity are challenging for most surfactants; however it is a common reservoir condition in many carbonate fields. The nanoparticles had a high degree of stability with little precipitation or gelation in the presence of salt content as high as 23 wt.% NaCl as long as the pH was sufficiently low. The stability of the nanoparticles decreased with increased temperature, leading to gelation and injectivity problems in limestone core samples when the injection water had native pH. The problem was less pronounced in sandstone core samples. Nanoparticle stability increased with decreasing pH, and it was possible to achieve steady-state conditions at 120 °C for longer periods of time. CO2 was shown to be a viable stabilizing agent by decreasing the pH of the injection brine and had the added benefit of creating stable foam for enhanced oil recovery. This is particularly important in limestones and carbonates where the pH of the injection water tends to increase as it interacts with the rock. The nanoparticles can be used alone or in combination with surfactants to increase the stability the surfactant generated foam. Surfactant based foam is generally more effective at generating foam, but is less stable at harsh conditions than nanoparticles.

Mobility control is one of the most important parameters in chemical enhanced oil recovery (CEOR). Hydrolyzed polyacrylamide (HPAM) polymer, the standard mobility-control agent, is often degradable and causes poor sweep efficiency under changing shear rates and at temperatures above 140 °F. Under these conditions, HPAM solution loses more than 90% of its viscosity and is unable to sustain appropriate viscosity necessary for residual oil displacement. Therefore, a wormlike micellar (WLM) solution was developed as a substitute mobility polymer for CEOR applications. The WLM solution is composed of chains, bonded by electrostatic forces, which can deform and reform rather than permanently breaking down when subjected to high shear rates and temperature fluctuations. In this study, two compositions of WLM solutions were chosen and prepared in the laboratory. For each of these two solutions, their effectiveness was determined by comprehensive thermal compatibility tests; interfacial tests (IFT); and rheological tests to evaluate the impact of concentration, shear rates, salinity (NaCl = 3.5%, CaCl2 = 0.05%, and MgCl2 = 0.05%), and temperature (86 to 158 °F) on viscosity. Next, the core displacement test was performed to examine the residual oil displacement by a mixed-surfactant WLM solution (zwitterionic surfactant 1.09% w/v, R = 0.55). Test results determined that both of the tested WLM solutions showed great potential in high-salinity and high-temperature conditions. Each of the two WLM solutions was equally adaptable and unrestricted, despite differences between the components of each formulation. With the addition of salts, the WLM solutions were highly tolerant over the entire range of shear rates. At 158 °F, the thermal degradability of WLM solutions was less than HPAM polymer. In addition to this, IFT between crude oil and WLM solution was also observed to be very low compared to the typical water-and-oil system. Moreover, the WLM solution produced an additional oil recovery of 10.9% beyond secondary recovery during the coreflooding test. Hence, the results supported WLM solutions to be potential mobility control for CEOR. WLM solutions have been successfully shown to perform beyond the salinity, temperature, and shear-rate limitations of HPAM polymers. This makes WLM solutions more flexible, not only for EOR applications, but also for well completion, well stimulation, and for coiled-tubing cleanout processes following gravel-pack operations.

Many carbonate reservoirs in Middle East under water or gas injection exhibit poor or limited vertical sweep efficiency due to channeling of the injected fluid through high permeability streaks (high-k streaks) and/or gravity segregation. In this paper, causes of the limited sweep efficiency and its possible mitigation measures are discussed through conceptual reservoir simulation and the force balance (FB) analyses of their results. The analyses are based on convention-diffusion-gravity (CDG) formulation, and applied to five-spot waterflood, line drive waterflood and line drive gas flood schemes to provide insights to improve reservoir development strategy.In waterflood either in five-spot or line drive scheme, the injected water moves fast in a high-k streak in oil-wet reservoirs where the effect of convection decreases rapidly and the diffusion has no or limited contribution to diverting the water from the high-k streak to neighboring layers, leading to early water breakthrough and poor sweep efficiency. Gravity force works to slump the water into the high-k streak, thus accelerates water breakthrough especially in case the high-k streak is located at the bottom of the reservoir. For such reservoirs, the practical mitigation strategy will be to delay the decline of the convection effect. Mobility control is the effective mitigation measure in this regard. In-depth conformance control is another mitigation measure in line with this strategy. If the blocking is implemented sufficiently away from the wellbore and with sufficient blockage width, it can make similar level of positive impact on waterflood performance as that expected by mobility control with minimal impairment of injectivity.In gas flood under unfavorable mobility ratio, gravity override is the key risk even in homogeneous reservoirs. Gas breakthrough is further accelerated in case the high-k streak is located in the upper part of the reservoir. In such reservoirs, the principal mitigation strategy will be to reduce the relative effect of gravity force in addition to increasing the gas front saturation. Enhancement of the viscosity of the injectant will realize both, thus lead to significant improvement of vertical sweep and oil recovery. On the other hand, in-depth conformance control will have positive but limited impact on gas flood performances.Considering the study results mentioned above and the state-of-the-art of the related technologies, mobility control is considered to be the principal solutions to the poor vertical sweep both for waterflood and gas flood, and in-depth conformance control can be another cost effective solution for waterflood in the oil-wet carbonate reservoirs associated with high-k streaks.

Waterflooding in low permeability, fractured and oil-wet carbonate reservoirs yields extremely low oil recovery due to bypassing through fractures and little imbibition into the matrix resulting in a large amount of oil remaining in the reservoir. Gravity-aided gas injection is studied at the lab-scale in this work to enhance oil recovery from fractured reservoirs. The miscibility of the gas with a model oil (decane with naphthenic acid) is varied by enriching the methane with ethane. Mobility of the gas is decreased by incorporating the gas in foam or glycerol-alternating-gas floods. As the miscibility increases, the oil recovery increases, but reaches a plateau above the near-miscible conditions. The foam flood improves oil recovery by diverting gas into the matrix, if the gas is sufficiently soluble in the oil and the gas-oil capillary pressure is sufficiently low. The pressure gradient generated in the fracture by foam helps in the diversion of the gas into the matrix. Glycerol-alternating-gas floods result in minor additional oil recovery over foam floods because the pressure gradients are about the same. These experiments need to be repeated after gas floods (before conducting foam floods). Near-miscible (and miscible) foam floods increased the oil recovery to high values (about 85% OOIP) in core floods and their scale-up to reservoir scale warrants further study.

According to the strategy to search alternative products which can replace (partially) the use of expensive polymers in polymer-flood projects, this work helps to find the optimum combination between polymer and xanthan-gum to develop a mixture that generates viscosity in good economical and rheological conditions. The aim of this work is the characterization of the mixture of a biopolymer (xanthan gum) and a synthetic polyacrylamide in specific proportions and reservoir conditions. Both polymers are suitable for polymer flooding, but they have weaknesses on their own: the polyacrylamide is very susceptible to saline environments and mechanical degradation, while biopolymers as xanthan gum exceed these reservoir conditions but are highly degraded by some bacteria. A polymer blend of mother solutions was prepared by mechanical mixing. It is proved that a blend improves the desirable properties of mobility control if the polymers show miscibility. Several techniques were used to evidence possible interaction between the polymers. A series of tests were performed to provide complementary data regarding molecule structure, miscibility, interaction and stability of the xanthan gum-polyacrylamide mixture at 35/65 proportion in a 16,000 ppm TDS reservoir synthetic brine. The polymer mother solutions and the mixture were lyophilized in order to determine thermal events by Differential Scanning Calorimetry (DSC), Differential Thermal Analysis (DTA) and Thermo Gravimetric Analysis (TGA). Also Fourier Transform Infrared (FTIR) spectroscopic studies and Proton Nuclear Magnetic Resonance (1H NMR) were performed to obtain distinctive molecular fingerprint; and Scanning Electron Microscopy (SEM) so as to complete the morphological studies. This work shows detailed techniques of the characterization and the conclusions achieved that confirm the molecular interaction of the blend. DSC analysis at low temperatures evidence similar vitric transitions for xanthan gum and polyacrylamide mother solutions. Vitric transition temperature (Tg) is related to the polymer network packing and hydrodynamic volume, concluding that similar values means that both polymers can travel together through the porous media without being segregated. The single Tg obtained for the mixture could indicate interactions between the polymers. This interaction was also shown in the FTIR analysis: the mixture spectra showed displacement of some signals of the fingerprint zone. On the other hand, the 1H NMR spectra of the mixture did not show differences with the pure polymers ones. SEM micrographies show no surface separation: xanthan gum deposits over the continued and directional layers of polyacrylamide evidencing phase integration. Blends of bio and synthetic polymers are investigated widely in other industries due to their benefits. Up to date, there are no reports of the use of polymer mixtures in polymer flooding. The results of this work will enable the design of a pilot to be conducted during 2018 on a mature polymer-flooded area with more than 10 years of polymer-flooding (Buciak, 2013).

CO2-foam has been used as a fracturing fluid to develop unconventional resources and specifically for water-sensitive reservoirs. CO2-foam not only reduces formation damage by minimizing the quantity of aqueous fluid which enters the formation, but also reduces the water consumption for environmental conservation purposes. CO2-foam as a hydraulic fracturing fluid provides for rapid cleanup during flowback. Although it is common to use surfactants to generate and stabilize foams, they tend to degrade at high temperatures (>212°F) and in high-salinity environments. The present work evaluates new foaming solutions that incorporate nanoparticles to investigate the mobility-control performance when such foams are used as hydraulic fracturing fluids. Of special interest in this work is the study of mobility reduction factor (MRF) of CO2 foam, generated with polymer-based solution, e.g., guar gum, in the presence and absence of nanoparticles, to assess the apparent fluid viscosity at high temperature and high salinity. To achieve this objective, coreflood tests were conducted on different Buff Berea sandstone cores at both 77 and 250°F. CO2 gas was injected with the different solutions simultaneously to generate foam with 80% quality. The pressure drop across the core was then measured to estimate the MRF. Results show that alpha olefin sulfonate (AOS) improves the MRF by 300% compared to NaCl solution. Adding silica nanoparticles and guar-gum to the AOS solution improves both foam stability and MRF. At 250°F, the AOS solution retained foam stability, while the MRF increased to 28 compared to that of at 77°F. Choice of surfactant concentration is a critical parameter in generating stable foam. However, the economical use of surfactants is limited by various factors such as surface adsorption, process cost, surfactant loss, and surfactant degradation at high-temperature reservoirs. Nanoparticle solutions can be employed to improve CO2 foam stability as well as MRF factor. Adding nanoparticles is highly recommended for hydraulic fracturing applications, particularly in fracturing stimulation at high-temperatures.

CO2 foam has been used for different oil and gas applications such as hydraulic fracturing and enhanced oil recovery (EOR). Foam is used as a fracturing fluid to develop unconventional reservoirs and specifically water-sensitive reservoirs. It is also employed as an EOR fluid to control fluids mobility and improve sweep efficiency. Moreover, using foam as a hydraulic fracturing fluid provides rapid cleanup during flowback. Although it is common to use surfactants to generate and stabilize foams, they tend to degrade at high-temperatures (>212°F) and in high-salinity environments. Adding nanoparticles is a new technique to stabilize CO2 foams that supports the proppant-carrying requirements for fracturing fluids. The present work evaluates new foaming solutions that incorporate nanoparticles to investigate the mobility-control performance when these foams are used as hydraulic fracturing fluid. This study specifically investigates the effect of nanoparticles on the stability of alpha olefin sulfonate (AOS) foam and the corresponding mobility-reduction factor (MRF), which indicates the apparent fluid viscosity at high-temperature and high salinity. To achieve this objective, foamability and foam stability tests were conducted at 77 and 150°F. Foam stability was studied for various solutions using a high-pressure view chamber (HPVC) setup to find the optimal solution, at which higher foam stability in the CO2 foam system can be reached. Coreflood tests were also conducted on different Buff Berea sandstone cores at both 77 and 250°F. CO2 gas was injected with the different solutions simultaneously to generate foam with 80% quality. The pressure drop across the core was then measured to estimate the MRF. The results of this work show that foam half-life decreases as the temperature increases from 77 to 180°F. Nanoparticle-based foams are more stable over time compared to those stabilized by surfactant. AOS, as an anionic surfactant, improves the MRF by 300% compared to brine alone. Adding silica nanoparticles to the AOS solution improves the foam stability and increases the MRF eight-fold. At 250°F, the AOS solution retained foam stability, while the MRF increases to 28 compared to foam at room temperature. Surfactants may degrade at high temperatures, and hence, cannot be used to stabilize foam. Protecting surfactants from being degraded and improving the foam stability is of great importance and can be achieved by adding nanoparticles to the solution. Nanoparticle solutions can be used to improve CO2 foam stability. Adding nanoparticles is highly recommended for hydraulic fracturing applications, particularly in fracturing stimulation at high-temperatures.

Nanotechnology is the design and application of engineered or naturally occurring nanoparticles with at least one dimension of the order of 1–100 nm to accomplish specific purposes. Nanoparticles possess three unique properties. First, their small size enables nanoparticles to be transported into formation pores not accessible to larger particles. Second, at nanoscale, material properties are size dependent. Therefore nanoparticles can be engineered to contain specific optical, magnetic, interfacial, electrical or chemical properties to perform specific functions. Third, they have a very large surface-to-area ratio. Combined together, these unique properties allow nanoparticles to be used for many purposes in the oilfield. The objective of this paper is to conduct a critical review of the recent literature to determine the status of research and development and field application of nanotechnology to the oilfield. Most of the proposed applications of nanotechnology in the oilfield can be classified into the following six areas: (1) sensing or imaging, (2) enhanced oil recovery (EOR), (3) gas mobility control, (4) drilling and completion, (5) produced fluid treatment, and (6) tight reservoir application. Our review shows that much of the current research is focused on the performance of nanoparticles in the reservoir. Some work is done of the propagation of nanoparticles and very little work is done on the delivery and recovery of nanoparticles. In addition, a lack of well-defined health, safety and environmental protocols for safe delivery and recovery of nanoparticles can be a showstopper and more focused research is needed in this area. Our work also shows that affordability of nanoparticles is another showstopper due to the large quantity needed for oilfield applications and the current lack of vendors. As a remedy, we propose focused research and development on the use of naturally-occurring and industrial waste nanoparticles for oilfield applications. Of the six application areas, we rank imaging, drilling through unstable zones, tight reservoir applications and EOR as ones having the biggest potential impact. Using nanoparticles to detect hydrocarbon saturation in a reservoir can significantly impact how we plan field development, such as well placement. Similarly, using nano-enhanced drilling fluid to stabilize and drill through unstable zones can increase rate of penetration, reduce drilling cost and minimize environmental impact. Furthermore, using specially-designed nanoparticles to image and prop up induced and naturally occurring fractures in tight reservoirs can lead to sweet spot identification and more prolific wells. With its ability to make reservoir rocks more water-wet, waterflooding by nanofluids also has the potential to augment or replace low-salinity waterflooding as an EOR method.

Recent research indicates that even small viscous transverse pressure gradients can increase the rate of surfactant imbibition into the matrix of a fractured reservoir. However, surfactants are commonly tested using static imbibition cells without any imposed pressure gradient. Therefore, the effect of viscous pressure gradients was investigated by conducting a series of surfactant corefloods using fractured Silurian Dolomite and Texas Cream Limestone cores. The viscosity of the surfactant solution was increased by adding polymer or by changing the salinity of the aqueous surfactant solution, which affects the in-situ microemulsion viscosity. The fractured cores had a permeability contrast between the fracture and the matrix ranging from 2500 to 90,000. Non-fractured corefloods were also performed and compared with the fractured corefloods. The more viscous surfactant solutions achieved greater oil recovery from the fractured carbonate cores. These results indicate that a viscous microemulsion can serve as a mobility control agent in naturally fractured reservoirs (NFRs) that is analogous to mobility control with foams and polymers, but with less complexity and cost.

The aim of this paper is to investigate an application of nanofluid-slug preflush to enhance well injectivity while improving the sweep efficiency by fines migration-assisted mobility control in multi-layer heterogeneous reservoirs during low salinity water flooding. An axisymmetric radial flow model and fraction flow analysis are applied to interpret the performance of nanofluid-slug and the following low salinity water injection in a layered heterogeneous flow system. The interplay among nanoparticles, fines and rocks is described by a physical-chemical reaction model. The improvement of mobility control is characterized as the ratio of displacement fronts' advancing velocity along each layer. The improved well injectivity by nanofluid preflush is presented as an explicit formulation of injectivity index. This paper also introduces a graphic workflow to optimize nanofluid treatment and injected water salinity for nanofluid-fines-assisted low salinity water flooding under arbitrary initial and injection conditions. The results indicate: 1) Compared with conventional water flooding, the alteration of water salinity can help to achieve uniform water flooding profile within each heterogeneous layer and then improve sweep efficiency before water breakthrough; 2) The nanofluid preflush prior to water injection can effectively control fines migration in the vicinity of injection wells to improve well injectivity, but it cannot control fines migration in reservoirs that realizes mobility control by decreasing water-phase permeability in the higher permeable layers; and 3) there does exist an optimal nanofluid concentration and slug size to offset decline of permeability near wells and then improve water injectivity. The outcomes of analytical model are validated by both numerical simulations. This paper has the following novel points: 1) the model provides physical insights to examine nanofluid utilization to improve well injectivity and enhance oil recovery; 2) The induced mobility-control by fines migration during low salinity water flooding is confirmed as an effective method to improve sweep efficiency in heterogeneous reservoirs.

Alkali flooding in heavy oil reservoirs is known to stabilize emulsion in-situ and improve the recovery beyond that of conventional waterflood under certain boundary and initial conditions. The overarching goal of this study is to develop a systematic approach to optimize this process and capture underlying recovery mechanisms. Therefore, we experimentally evaluated the performance of alkali flood as a function of emulsion type and viscosity. Phase behavior and viscosity of the microemulsion are modified by introducing seven different surfactants. Microscope imaging techniques are employed to measure the droplet size distribution for type I and II emulsions. Viscosities of generated emulsions are measured with a rotational rheometer at low temperatures and with an electromagnetic viscometer at reservoir conditions. Finally, corefloods are conducted at different conditions to evaluate the performance of displacement as a function of emulsion type and viscosity. Enhanced alkali floods showed an incremental recovery of 8 – 50% beyond that of waterflood. Formation of higher viscosity emulsion has a large contribution on the sweep efficiency and therefore improved oil recovery during alkali flood; however, other mechanisms (e.g. entrainment and entrapment) also have contribute to the incremental recovery. Results of our experiments indicated that the incremental recovery is a strong function of emulsion type, emulsion viscosity, and the droplet size distribution.

CO2 miscible and immiscible displacements and hydrocarbon miscible floods are commonly plagued by low volumetric sweep efficiency, early gas breakthrough, high gas utilization ratios, and significant gas re-compression and recycle. Rather than addressing these problems via the water-alternating-gas (WAG) injection sequence that reduces gas relative permeability or the generation of gas-in-brine foams for reduced mobility, we propose increasing the viscosity of high pressure CO2 or NGL via the dissolution of dilute concentrations of thickening agents. There are two strategies for increasing the viscosity of high pressure fluids; the dissolution of ultrahigh molecular weight polymers or associating polymers, or the dissolution of small molecules that self-assemble in solution to form viscosity-enhancing linear or helical supramolecular structures. Ideally a very small amount of the thickener will be required (roughly 0.1wt%) to elevate the CO2 or NGL viscosity to the same value as the oil being displaced (typically a 10-100 fold increase). Further, the thickened CO2 or thickened NGL should be a stable, transparent solution that does not require a heating/cooling cycle for viscosity enhancement to occur. Thickener solubility and viscosity were determined over a 25-100oC range. Each of the three major NGL constituents (ethane, propane and butane) was thickened with an ultrahigh molecular polymer (commercial drag reducing agent), resulting in a 2-30 fold increase in viscosity at polymer concentrations of 0.5wt% or less. The polymer dissolved at the lowest pressure in butane and was most effective as a thickener in butane. Three small molecule thickeners were identified for the NGL constituents; tri-alkyl-tin fluoride, hydroxyaluminum disoap, and a phosphate ester-crosslinker mixture. Remarkable viscosity enhancements were attained for propane and butane with the tri-alkyl-tin fluoride and aluminum soap; the crosslinked phosphate ester solutions exhibited modest viscosity increases. Only tri-alkyl-tin fluoride thickened ethane. CO2 thickeners were assessed with a falling ball viscometer and pressure drop associated with flow through Berea sandstone. 4-5 fold increases in viscosity were attained with 1wt% of a high molecular weight polyfluoroacrylate. 3-4 fold increases in viscosity were attained with 1wt% high molecular weight polydimethyl siloxane, but a very large amount of toluene co-solvent was required. Although a remarkably effective small molecule thickener was designed for CO2 (100-fold increase at 1.3wt%), it required a heating/cooling cycle and a very large amount of hexane co-solvent. We have identified the first polymeric and small molecule thickeners ever reported for ethane. Further, this study presents the largest viscosity increases ever reported for propane and butane with polymers and small molecule thickeners. We have presented the most effective polymeric thickeners for CO2 reported to date. This paper also summarizes numerous molecular architectures that are not viable for CO2 and highlights the most promising compounds that continue to be refined.

This work investigates the use of polymers during CO2 WAG using a physical model. Coreflooding experiments were conducted to compare polymer assisted WAG, conventional WAG, continuous CO2 flooding, and polymer flooding. The effect of miscibility in the CO2 – oil interface was evaluated from coreflooding at two different pressures, above and below the MMP of 1563 psig The MMP was experimentally determined using a fast version of the slim tube procedure with a shorter column. The influence of reservoir heterogeneity was observed by conducting corefloodings in homogeneous and heterogeneous rocks with permeability ranging from 13 to 1300 md. The core plugs were selected using computed tomography to ensure the presence or absence of heterogeneous features. Our results show that under miscible displacement in a homogeneous rock, continuous CO2 injection can reduce residual oil saturation (Sor) to less than 10%, even for a permeability as low as 13 md. The implementation of conventional WAG and polymer assisted WAG in this case was detrimental for the process as water saturation shielded a portion of the oil preventing CO2 contact. The departure from the ideal miscible displacement resulted in a Sor as high as 32 %. For the heterogeneous rock, at 285 psig above MMP, the WAG CO2 was able to reduce Sor to as low as 11%, whereas at 260 psig below MMP a Sor of 23% was reached. As the level of heterogeneity increases, the oil recovery of polymer assisted WAG relative to conventional WAG increased suggesting that a certain degree of heterogeneity is needed for the polymer assisted WAG process to be beneficial. A throughout discussion on the recovery mechanisms and the interactive / combined role of miscibility, heterogeneity, permeability and viscosity is presented. This work adds to the understanding of the CO2 flooding process implemented in the North Burbank Unit (NBU) and the potential to use WAG and polymer assisted WAG to improve mobility control. Sweep efficiency is the most important challenge from a reservoir engineering standpoint for CO2 flooding, but it is particularly critical in the NBU for two reasons. The high vertical heterogeneity in the field, with a permeability variation of three orders of magnitude within 30 ft of reservoir thickness, which greatly exacerbates viscous fingering, and the use of anthropogenic CO2 which makes the economics of the project more sensitive.

On water flooding process, water preferential flow through high permeability, fractures, and large channels; cause a large amount of recycling of water without much benefit to oil production. Preformed particle gels (PPGs) have drawn more attention to reduce the fluid flow in these large opening features and to improve macroscopic oil efficiency. In spite of the successful applications of using PPGs in plugging such large features, there is still need to combine PPGs with other technology to produce more oil from the low permeable rich zones. The ultimate purpose of this study is to investigate the effectiveness of combining conformance control treatment using PPGs with mobility control using polymer to enhance oil recovery from both swept and un-swept oil zones. PPGs was injected into large permeability zones to reduce their permeability while polymer injected after gel to further increase oil recovery from the low permeability zones. Two separate parallel tubes packed with different sand grain sizes were designed to emulate the case when there is non-cross flow heterogenity between the low and the high permeability layers in the reservoir. Experiments were designed to examine the effect of permeability contrast ratio on the performance of coupling PPG and polymer to increase oil recovery. The results show a significant increase in oil recovery from both low and high permeability cores after performing polymer flooding right away after gel treatment. The oil recovery incremental was varied and strongly dependent on permeability contrast ratios. PPGs improved oil sweep efficiency significantly when the core permeability layers became more heterogeneous. Injection profile was improved after the PPG treatment, thus oil recovery from the low permeability cores was increased significantly.

In this Paper, Wormlike Micellar (WLM) solutions were studied as an alternative to polymeric mobility control agent in chemical enhanced oil recovery. In which, two compositions of WLM solutions were chosen and prepared in laboratory – Hexadecyltrimethylammonium Bromide/Sodium Nitrate and Three-(N, N-Dimethyloctadecylammonio) Propane-Sulfonate/Sodium Dodecyl Sulfate (TDPS)/Sodium Chloride. Then following experiments were conducted – thermal stability test, rheological measurements to account the effects of concentration, shears rates, salinity (NaCl = 3.5% w/v, CaCl2 = 0.05% w/v and MgCl2 = 0.05% w/v), and temperature (30 to 70 0C) on viscosity of these WLM solutions. Another stability test was conducted to test the effect of crude oil on WLM solution. The results showed that WLM solutions have excellent rheological resemblances with HPAM polymer solutions. On addition of salts, the WLM solutions were highly tolerant over entire range of shear rates. At 70 0C, the thermal degradability of WLM solutions was less than HPAM polymer. Despite of all these significances viscosity of WLM solutions was deemed to the viscosity of water (1 cP) on mixing crude oil. It was due to strong interfacial activity between surfactants present in WLM compositions and crude oil. Such as, the IFT between crude oil and WLM solution was observed very low (0.3 to 0.55 mN/m) as compared to the typical system of water-oil (20 to 50 mN/m). Besides, core flooding was performed by mixed surfactant WLM solution (TDPS = 1.09% w/v, R = 0.55) at 70 0C. The WLM solution produced an additional oil recovery of 10.9% beyond secondary recovery. Thus the results supported WLM solution to be potential mobility control for chemical EOR.

The goal of this work is to develop a novel way of beneficially utilizing two main waste products from coal power-generation plants – carbon dioxide and fly ash – by generating fly ash nanoparticle-stabilized CO2 foam for CO2 EOR mobility control. First, as the grain size of fly ash is generally too large for injection into reservoirs, it was reduced to nano-size by the ball-milling process. Second, dispersion stability analysis was performed to evaluate a suitable dispersing agent for fly ash nanoparticles (FA-NP). A range of surfactants (anionic, cationic, and non-ionic) was used in dilute concentrations. Surfactants were screened based on particle-hydrodynamic diameters and polydispersity index of the dispersion as measured by dynamic light scattering. Third, foam flow experiments were performed using combinations of FA-NP and various surfactants. Aqueous foam was created in-situ by coinjecting the FA-NP and/or surfactants with liquid CO2 through a sandpack at a fixed foam quality. Foam texture, as seen in the view-cell, was used to screen suitable surfactants that stabilized strong foams. Finally, the foam flow experiments were conducted in a Berea sandstone core. Pressure drop across the core was measured to estimate the achieved foam resistance factor and the apparent viscosity of the generated foam. Nano-milling and thermal treatment processes were able to yield thermally-treated fly ash (TTFA) nanoparticles with an average size of 180 nm. Dispersion stability analysis revealed that anionic and non-ionic surfactants are suitable in dispersing these nanoparticles. Foam texture visualization demonstrated that strong carbon dioxide-in-water foam/emulsion with fine texture can be generated using TTFA nanoparticles in porous media in conjunction with a non-ionic surfactant or an anionic surfactant in dilute concentrations. Foam flow experiments in a Berea core showed that TTFA nanoparticles even in low concentrations (0.4 wt%) can significantly improve the foam stability and foam resistance factor of an anionic surfactant (in the absence of oil). Antagonistic effects were observed in foam stability in Berea core by addition of TTFA nanoparticles to nonionic surfactants. This study has the potential of not only to minimize the surfactant usage for foam-based CO2 EOR mobility control, but also to sequester both CO2 and fly ash in subsurface formations.

The work presented in this paper evaluates the potential of Low-Tension Gas (LTG) as an alternative to polymer flood for displacing the surfactant slug in a chemical EOR process in ultra-high salinity (above 189,000 ppm TDS), high temperature (above 85°C) sandstone reservoirs. The LTG process involves the use of surfactant and gas to achieve the mobility control required to displace the micro-emulsions and the crude oil. The optimal formulation of surfactants is identified to obtain good oil/water microemulsion phase behavior and desirable high optimum salinity. The latter feature allows the LTG process to work with a wide variation of injection brine salinity or in-situ salinity gradient. The optimal injection strategies are then determined through a series of oil recovery core floods with co-injection of gas and the surfactant solution. Tertiary recovery of up to 90% of the residual OIP was achieved for cores with 150–400md air permeability. The high optimum salinity that is closest to the formation brine salinity was found to give the highest incremental oil recoveries. Macroscopic stability of displacement fronts was studied via pressure derived mobility ratios. Approximate parity of relative mobility of injected fluids was observed with respect to relative mobility of displaced water at true residual oil saturation and interpreted relative mobility of a formed oil bank. These results indicate that in-situ foam propagation was present which enabled mobility control, and that stable displacement of in-situ fluids was achieved during flooding. By replacing polymer with foam, chemical EOR methods can be expanded into formations where the use of polymer is impractical.

One of the major challenges envisaged in the application of WAG in multilayered reservoir with large thickness is poor conformance of injectants. Critical premises in the success of any enhanced oil recovery flooding operation is that mobile oil volume should be increased and this increased volume is contacted by driving fluids to enable it to be produced from the producers. This oil volume should not be by-passed by the EOR injectant fluid. Another important aspect is that driving fluids and fluid front of mobilized oil needs to flow more or less equally throughout the reservoir. This happens when reservoir conformance is well addressed. Therefore, controlling the flood front in WAG injection is a major challenge in the success of immiscible WAG injection. This paper presents laboratory research, lab and pilot design modeling study for developing the suitability of foam for a challenging reservoir. Foam was generated by simultaneous injection of CO2 rich injection gas with selected surfactant formulation initially saturated with surfactant. Effect of series of injection rates were investigated as main parameters for foam propagation and stability under field condition. It was observed that mobility reduction factor (MRF) increases with increasing flow rates and stabilized when the flow rates were decreased. The effects of multiple injections at fixed flow rates and from low to high rates through Surfactant Alternating Gas (SAG) were compared. SAG at low rates not adequate in generating strong foam thus produced very low MRF. SAG at multiple small slugs from low to high rates generated high MRF caused by frequent contact and mixing between surfactant and gas. Co injection and multiple injection through SAG indicated moderate MRF are obtained at high flow rates as in the near wellbore area and high MRF ensuring good mobility control and sweep efficiency when foam propagates within the reservoir.

Summary Foam generation for gas mobility reduction in porous media is a well-known method and frequently used in field applications. Application of foam in fractured reservoirs has hitherto not been widely implemented, mainly because foam generation and transport in fractured systems are not clearly understood. In this laboratory work, we experimentally evaluate foam generation in a network of fractures within fractured carbonate slabs. Foam is consistently generated by snap-off in the rough-walled, calcite fracture network during surfactant-alternating-gas (SAG) injection and coinjection of gas and surfactant solution over a range of gas fractional flows. Boundary conditions are systematically changed including gas fractional flow, total flow rate, and liquid rates. Local sweep efficiency is evaluated through visualization of the propagation front and compared for pure gas injection, SAG injection, and coinjection. Foam as a mobility-control agent resulted in significantly improved areal sweep and delayed gas breakthrough. Gas-mobility reduction factors varied from approximately 200 to more than 1,000, consistent with observations of improved areal sweep. A shear-thinning foam flow behavior was observed in the fracture networks over a range of gas fractional flows.

Nanoparticle stabilized CO2 in water foam can overcome the low stability challenges facing surfactant foams in reservoir conditions. Foams are effective in mobility control against viscous fingering during gas injection in enhanced oil recovery. This study presents a microfluidic approach to image and quantify the stability of foam at pore scale and the dynamics of the oil recovery process during water flooding, CO2 gas flooding, and nanoparticle foam flooding. In addition to chip scale flooding visualization, micro-scale imaging reveals the mechanisms of the viscous fingering in gas flooding and the high sweep efficiency of foam; micro-emulsion size and distribution in gas and foam flooding. Coated silica nanoparticle CO2 foam is significantly more stable than sodium dodecyl sulfate (SDS) foam at both pore scale and bulk foam. Nanoparticle foam can improve oil recovery an additional 17% IOIP after water flooding, this is 10% IOIP more efficient than CO2 gas flooding as a result of high sweep efficiency and increase in effective viscosity.

The application of CO2 injection for mobilization of trapped oil in porous media is the most frequently applied method for EOR projects. Despite of the fact that the CO2 injection can effectively mobilize the trapped oil, many problems such as viscous fingering, gravity override, high ratio of CO2 to oil produced and early breakthrough are required to be resolved. In this context, the injection of surfactant solution for the reduction of CO2 mobility is a promising method. However, until now surfactants usage for mobility control is facing many challenges such as, adsorption of surfactants on rock, requirement of copious amounts of water, and loss in the thief zones of reservoir. These challenges can effectively be reduced by employing CO2 soluble surfactants, which have exhibited more practical advantages over conventional surfactants. A study has been conducted to evaluate new CO2 soluble surfactants for the CO2 mobility control for EOR applications. The IFT between CO2 and synthesized surfactants solution was studied for the initial screening process and is reported. The coreflood experiments were conducted by using Berea core sample in order to measure the mobility reduction factor (MRF). The MRF value of 3.1 was obtained by the incorporation of 0.5 % of novel CO2 philic foaming agent. Moreover, it was observed that the IFT between CO2 and brine appreciably decreased by using the surfactant in 0.5 % concentration. Coreflood results showed that, as compared to conventional surfactants, newly developed CO2 philic surfactants significantly reduced the mobility of the injected CO2.

Mature water floods with high-permeability sands and medium to heavy-gravity crude oil are prime candidates for enhanced oil recovery (EOR) methods. We examined actual field results from the Buffalo Coulee reservoir. The simulation model was history matched on waterflooding and primary. Forecasts were performed with waterflooding and polymer flooding as well as gel treatments. Results indicated that polymer flooding resulted in a 5 to 8% incremental recovery factor over water flooding, while gel treatments resulted in a 2 to 4% incremental when applied separately. However, when gel treatments were performed immediately prior to polymer flooding, simulation showed the incremental recovery was much higher at 10 to 15%. In other words, there was a large synergistic effect of gels with polymers. As seen from long-term production data, interwell tracer analysis, pressure pulse tests, and communication analysis, many waterfloods develop preferred water channels due to preferential flow pathways and/or waterflood-induced fracturing. These channels sometimes cycle large volumes of water from injectors to producers in waterfloods with very high water cuts. These channels also can significantly affect the chemical EOR process. Therefore, it is critically important to understand these preferential paths and flow mechanisms in the reservoir and then, in some cases, take corrective action before tertiary EOR is implemented. Permanently plugging these water channels using crosslinked gel has some significant impacts on improving chemical EOR efficiency and waterflood efficiency. The synergistic effect of the combined treatment significantly improves chemical EOR economics by reducing chemical demand, increasing oil production, decreasing water production, and increasing volumetric sweep.

The goal of this work is to evaluate stabilization of foams by a combination of nanoparticles and surfactants. Hydrophilic silica nanoparticles (NP) and anionic surfactants were used in this study. Static foams were generated using surfactants and surfactant-NP mixtures with and without the presence of a crude oil. The decay of the foam height with time was studied and half-lives were determined. The foam drainage behavior and thickness of the foam lamella were studied by fluorescence microscopy. Aqueous foams were created in-situ by co-injecting the surfactant or surfactant-NP mixtures with nitrogen gas through a Berea sandstone core at a fixed quality. Pressure drop across the core was measured to estimate the achieved mobility reduction factor (MRF). Oil displacement experiments were conducted in Berea cores using surfactant and surfactant-nanoparticle mixture as foaming agents. Static foam tests indicate stabilization effect of nanoparticles on surfactant-nanoparticle foam stability in the absence of crude oil. Lighter crude oils were more destabilizing to foams than heavier oils. Adding nanoparticles even in low concentrations (0.3 wt %) can significantly improve the foam stability and mobility reduction factor in the absence of oil. As the concentration of nanoparticles increased, mobility reduction factor (MRF) of surfactant-nanoparticle foam in a Berea core increased significantly. Fluorescence microscopy elucidated that nanoparticles are trapped in the plateau border as well as lamellas which retard liquid drainage and bubble coalescence. The core floods with a crude oil revealed that the incremental oil recovery by surfactant-NP blend over water flood was about 10% OOIP with an immiscible foam.

Foams used for mobility control in CO2 flooding, and for more secure sequestration of anthropogenic CO2, can be stabilized with nanoparticles, instead of surfactants, bringing some important advantages. The solid nature of the nanoparticles in stabilized foams allows them to withstand the high-temperature reservoir conditions for extended periods of time. They also have more robust stability because of the large adsorption energy required to bring the nanoparticles to the bubble interface.Silica nanoparticle-stabilized CO2-in-brine foams were generated by the co-injection of CO2 and aqueous nanoparticle dispersion through beadpacks, and through unfractured and fractured sandstone cores. Foam flow in rock matrix and fracture, both through Boise and Berea sandstones, was investigated. The apparent viscosity measured from foam flow in various porous media was also compared with that measured in a capillary tube, installed downstream of beadpacks and cores.The domain of foam stability and the apparent foam viscosity in beadpacks was first investigated with focus on how the surface wettability of nanoparticles affects the foam generation. A variety of silica nanoparticles without any surface coating and with different coatings were tested, and the concept of hydrophilic/CO2-philic balance (HCB) was found to be very useful in designing surface coatings that provide foams with robust stability. Opaque, white CO2-in-water foams (bubble diameter < 100 µm) were generated with either polyethyleneglycol-coated silica or methylsilyl-modified silica nanoparticles with CO2 densities between 0.2 and 0.9 g/cc. The synergistic interactions at the surface of nanoparticles (bare colloidal silica) and surfactant (caprylamidopropyl betaine) in generating stable CO2 foams were also investigated.The common and distinct requirements to generate stable CO2 foams with 5-nm silica nanoparticles, in rock matrices and in fractures, were characterized by running foam generation experiments in Boise and Berea sandstone cores. The threshold shear rates for foam generation in matrix and in fracture, both in Boise and Berea sandstones, were characterized. The ability of nanoparticles to generate foams only above a threshold shear rate is advantageous, because high shear rates are associated with high permeability zones and fractures. Reducing CO2 mobility in these zones with foam diverts CO2 into lower permeability regions that still contain unswept oil.

We propose a new strategy for carbon storage in which CO2 is injected into a geologic formation after emplacement of brine containing dispersed surface-modified nanoparticles. This strategy increases the sweep efficiency of CO2 storage in aquifers and enhances the aquifer storage security. The most likely mechanism is the generation of nanoparticle stabilized CO2/water foam which securely traps the injected CO2 for long periods of time.As a consequence of low density and viscosity of CO2 at typical geologic storage conditions, CO2 injection into aquifers suffers from low sweep efficiency which manifests as the gravity override and viscous fingering. Here, we show that nanoparticles can reduce the mobility of the injected CO2 as it displaces brine, and therefore, increase the sweep efficiency. Further we show that displacing the injected CO2 with brine increases residual phase saturations, and therefore enhance the capillary trapping of CO2.We conducted core flooding experiments in which liquid CO2 was used to displace brine with and without suspended nanoparticles. Sandstone cores with different degrees of heterogeneity were used to capture the effect of heterogeneity on the efficiency of the proposed technique. Saturation distributions and pressure drops were measured in real time with a modified medical CT scanner and pressure transducers. The use of nanoparticles is shown to render about 90% of the injected CO2 immobile and increases the sweep efficiency up to 20% when compared to the base brine case.

This work experimentally investigates a two-step, integrated EOR technique for heavily fractured, oil-wet carbonate rocks by combining fracture mobility control and chase fluid injections for increased sweep. The combination of mobility control using a cross-linked Cr(III)-Acetate HPAM polymer gel, and three different chase fluids (water, surfactant or CO2 foam) was investigated as an integrated EOR approach. Waterflood oil recovery was low with poor sweep efficiency and oil production from the fracture volume only. Fracture conductivity was significantly reduced after polymer gel placement in the fracture, leading to increased sweep and oil recovery during chase fluid injections, with oil recoveries up to 60%OOIP.

Foam has been used for controlling gas mobility during injection processes in order to mitigate the adverse effects of low gas viscosity, reservoir heterogeneity and gravity override. In addition, foam has also been employed in near-wellbore production, matrix acidizing stimulation, hydraulic fracturing, gas shut-off and water shut-off. The optimization of these operations requires a good understanding of the physical characteristics of foam and its behavior under reservoir conditions. Despite numerous experimental and theoretical studies on foam and some field applications reported in the literature, there is no comprehensive literature survey detailing the knowledge and experience gained through the application of foam. The aim of this paper is to present a critical review of the literature available on the use of foam injection for enhanced oil recovery. An extensive appraisal of the current status of foam application in EOR methods is a useful way of presenting advantages, shortcomings and limitations of the process as well as supplementary advances. Special attention has been given to the review of new research topics, such as the use of foam as a mobility control agent. Advances in more efficient foaming agents, additives and boosters are discussed. Moreover, in depth analysis of field applications of foam in EOR projects show that the main problems encountered during field-scale foam applications are related to foam stability, foam compatibility, as well as adsorption of the injected chemicals onto the rock surface. To address this, we discuss the evolution of the pilot field application and the reasons for inconsistency between laboratory results and field scale performance.

Carbon dioxide injection and its performance during sequestration activities rely on the ability of the injection well to inject the desired amount of CO2 for decades. However, the CO2-rock-water interaction may cause immense formation damage by plugging the pores and reducing the permeability. Its severe consequences will reduce oil and gas productivity and CO2 injectivity in the reservoir. In this study a numerical simulator is developed and it solves the fluid flow equations, chemical reactivity equations, particle transport and particles deposition equations to predict the amount of formation damage during CO2 injection. We found that it has high rate of chemical reactivity and dissolution of reservoir rock near the wellbore. The dissoluted reservoir rock particles get precipitated in the reservoir away from the injection well, plugging the pores and reducing the formation permeability. From the simulation result on the effect of reservoir depth and temperature, we found that deep oil and gas reservoirs are good candidates for CO2 sequestration than shallow reservoirs. Because the increased depth and temperature of a deep reservoir decrease the CO2 dissolution rate and lower the solid precipitation. Sensitivity analysis of CO2 injection rates was performed to identify the effect of CO2 injection rate on reduced permeability in deep and high temperature formations. It was found that increased CO2 injection rates and pressures enable to reach miscibility pressure. Once this pressure is reached, there are less benefits of injecting CO2 at a higher rate for better pressure maintenance, no further diminution of residual oil.

Alkaline–surfactant–polymer (ASP) flooding is a combination process in which alkali, surfactant, and polymer are injected in the same slug. Because of the synergy of these three components, ASP is the current worldwide focus of research and field trial in chemical enhanced oil recovery (EOR). This paper is to provide a comprehensive review of the ASP process. The reviewed topics include the following: ASP synergy and its EOR mechanisms Screening criteria Laboratory work Numerical simulation work Summary of pilots and large-scale applications Project economics Chemicals used Water quality Mobility control requirement Problems associated with ASP flooding and possible solutions In addition to the comprehensive review, future developments are also discussed. Data and analyzed results presented in this review will provide the reader with the updated information about ASP and a guide to read relevant papers for those who are new to chemical EOR. The survey data also provide operators with some reference data for their project design and optimization. © 2014 Curtin University of Technology and John Wiley & Sons, Ltd.

This paper presents a process for CO2 foam generation in the presence of nanosilica particles as supercritical CO2 and nanosilica dispersion flow through a sandstone core at reservoir conditions of 20°C and 1,200 psig. The generation of CO2 foam was observed in an online sapphire tube. Pressure drop across the core was measured to estimate the fluid mobility and foam resistance factor. Foam mobility and particle retention were investigated and core permeability after the CO2/nanosilica dispersion flooding was also measured to determine the particle plugging in the core. The application of the nanoparticle-stabilized CO2 foam for waterfloods residual oil recovery from sandstone cores was investigated. The results indicated that nanoparticle-stabilized CO2 foam could improve oil recovery after waterfloods in both low and high permeability cores. The total oil recovery by CO2 and nanosilica flood was 48.7% from the core with permeability of 33 md and 35.8% from the core with permeability of 270 md under the pressure of 1,200 psig.

This paper describes a s eries of nanoparticle-stabilized CO2-foam flow experiments performed at reservoir conditions of 20°C and 1200 psig. The generation of CO2 foam was observed in an online sapphire tube. Pressure drop across the core was measured to estimate the fluid mobility and foam resistance factor. Results from the experiments show that stable CO2 foam was generated when CO2 and nanosilica dispersion flowed through a core sample. CO2 foam can be generated with the nanosilica concentration as low as 100 ppm. With the increase of nanosilica concentration, foam mobility decreased and the foam resistance factor increased. It was also observed that the foam mobility decreased with increasing foam quality from 20% to 60% and then increased as the foam quality increased from 60% to 80%. The effects of flow rate on foam mobility indicated that CO2 foam mobility decreased with the flow rate increasing from 60ml/h to 160ml/h.

A major problem with polyacrylamide, the main polymer used in EOR, is its tendency to degrade under shear forces. Another polymer xanthan gum usually costs more than polyacrylamide and requires a biocide to prevent biodegradation. Micellar flooding has been reported extensively since the 70’s and as in the case of other chemical flooding, it has not been implemented widely due to the high cost of chemicals to form micelles. The high viscosity of the micelles also posed injection problems. However, strategic injection techniques can overcome the problem. The salinity of the formation water and temperature are also important parameters. All these usually restrict application of chemical EOR particularly surfactant and polymer flooding. However, current studies have shown wormlike-micelle surfactants such as those from cetyltrimethylammonium halides (CTAX) and cetylpridium halides (CPyX) can alleviate these problems. Wormlike micelles have been used in other areas such as home cleaner products and personal care products including shampoo and body wash due to its viscoelasticity. It also finds applications as fracturing fluids in oil fields. While earlier micelle studies proposed four or five components in forming stable micelles, the current studies showed that a surfactant and salt can form wormlike micelles. These micelles have the advantage of breaking and reforming under shear stress and therefore maintaining the viscosity. It is also viscoelastic and research has shown that viscoelasticity is able to reduce residual oil. This research studies the surfactants that can form wormlike micelles under high salinity, high temperature conditions and the salts that are required to form the micelles. Displacements studies conducted show good mobility control and work on injection strategy will be discussed.

For miscible displacement under most reservoir conditions, due to the very low viscosity of the CO2 phase, poor volumetric sweep efficiency is a critical weakness of CO2 enhanced oil recovery (EOR). In this paper, a dynamic process for generating nanoparticle-stabilized CO2 foam is presented, which is expected to reduce CO2 mobility during CO2 EOR. This paper also describes the factors of nanoparticle concentration, CO2/brine volumetric ratio, and total injection rate effects on dynamic CO2 foam generation and foam mobility. Dynamic supercritical CO2 foam was generated by the shearing of supercritical CO2 and nanoparticle dispersions in a glass- bead packed column. The foam image was observed in an online sapphire tube. Particle size was determined to be in the range of 60–90 nm. The experimental results showed that stable dynamic foam was generated at a shear rate higher than 1419s‒1 at 1500 psig and 25°C. The pressure differentials along the glass bead packed column and capillary tube were used to characterize the CO2 foam mobility and the corresponding apparent foam viscosity. It was found that the yield shear rate increased from 1419s‒1 to 3312s‒1 as the injection rate increased from 3.0ml/min to 7.0ml/min, and the apparent foam viscosity with nanoparticle dispersion was 1.5 to 2.5 times higher than that without the dispersion. The corresponding mobility was nine times higher. With increasing nanoparticle concentration, the normalized mixture viscosity increased and related mobility decreased. Furthermore, the apparent viscosity decreased slightly as the CO2/brine ratio was varied from 2 to 11 at the constant flow rate of 6ml/min.

CO2-dissolved polymers could be used as mobility control agents for CO2-EOR. Unlike classical CO2 mobility control techniques, using polymers would involve a single thermodynamically stable CO2 phase and would not require water injection, which would eliminate difficulties linked to well acidification. Developing an industrial "CO2-polymer" EOR method implies three challenges. i) Suitable polymers must be evaluated in terms of solubility in CO2 under reservoir conditions and thickening ability. ii) Polymer-oil and polymer-rock interactions must be understood. Their consequences in terms of effective polymer transport far from the injection wells and potential mobility or permeability impairment must be physically modeled. iii) Reservoir scale simulations must be carried out to determine an economically optimal scenario (with parameters such as viscous slug size and polymer concentration). Although the first of the abovementioned topics has received some attention from researchers in the past years, the two others have not been studied yet. In this paper, we report, for the first time, an investigation of polymer-oil and polymer-rock interactions from coreflood experiments involving polymer-thickened CO2. We have studied polydimethylsiloxane-based model systems whose solubility in CO2 and viscosity enhancement ability have been previously evaluated in the literature. The coreflood tests were carried out with an experimental setup designed to enable on-line viscosity measurements downstream the cores and quantitative compositional analysis of the effluents. Results show that part of the injected polymer is immobilized in the porous media, and that this phenomenon originates not only from adsorption/retention in the rock surface/matrix but also from polymer dissolution in residual oil. We have also observed that polymer immobilization had moderate impact in terms of injectivity degradation and no impact in terms of irreversible permeability reduction. These insights could be used as input data for reservoir simulation.

A thorough understanding of foam fundamentals is crucial to the optimum design of foams for improved/enhanced oil recovery. This study, for the first time, presents anomalous foam fractional flow solutions which deviate significantly from the conventional solutions at high injection foam qualities, by comparig Method of Characteristics and mechanistic bubble-population-balance simulations. The results from modeling and simulations based on coreflood experiments revealed that (1) there exist three regions: region "A" with relatively wet (or high fw) injection conditions where the solutions are consistent with the conventional fractional flow theory; region "C" with very dry (or low fw) injection conditions where the solutions deviate significantly; and region "B" in between which has a negative dfw/dSw slope showing physically unstable solutions; (2) for dry injection conditions in region "C", the solutions require a constant state (IJ) between initial (I) and injection (J) conditions, forcing a shock from I to IJ by intersecting fractional flow curves, followed by spreading waves or another shock to reach from IJ to J; and (3) the location of IJ in fw vs. Sw domain moves to the left (or toward lower Sw) as the total injection velocity increases for both weak and strong foams until it reaches limiting water saturation. Even though foams at high injection quality are popular for mobility control associating a minimal amount of surfactant solutions, foam behaviors at dry conditions have not been thoroughly investigated and understood. The outcome of this study is believe to be helpful to successful planning of foam field I/EOR applications.

Gas injection is a proven enhanced oil recovery method, especially for light oil reservoirs. The primary objective of gas injection is to improve the displacement efficiency and reduce residual oil saturation below the values usually obtained in waterflooding. However, the macroscopic sweep efficiency of gas injection can be suboptimal, mainly due to channelling, viscous fingering and gravity segregation of the injected gas. The macroscopic sweep of gas injection is further reduced for highly heterogeneous reservoirs. In this paper we examine the ability of both foam and polymer to provide mobility control to gas injection in a mixed-wet carbonate reservoir with high permeability contrast, i.e, high permeability zone on top of a low permeability zone. Under waterflood, there is an impediment for water to flow from the high permeable Upper zone to the Lower zone due to e.g., capillary pressure. The paper presents two new emerging technologies for mobility control of gas injection, which results in improving vertical sweep efficiency of oil reservoirs, namely: 1-SIMGAP: Simultaneous injection of miscible gas in the low permeable Lower zone and a polymer solution in the high permeable Upper zone. A lateral pressure gradient is maintained in the Upper zone by the injected polymer, providing Lower zone gas confinement; and2-Foam: Simultaneous injection of surfactant solution in the Upper zone and gas in the Lower zone. As gas migrates to the Upper zone, foam will be created in-situ and reduces both gas and water mobility in the Upper zone. This leads to the containment of the gas in the Lower zone, thus improving vertical sweep of the reservoir. The EOR processes are compared based on recovery factor, possibility of success, robustness to geological heterogeneity and operating conditions and stability at high temperature and salinity conditions. Simulation results show that the two EOR processes have the potential of recovering the oil that is by-passed by waterflood or conventional gas injection schemes. The SIMGAP process (polymer based) leads to higher recovery factor than the foam process. Experimental data supporting simulation work was also conducted as part of this study.

Experimental studies have shown that the steam foam process can be significantly enhanced by injecting a suitably formulated alkali-surfactant mixture in the aqueous phase of steam. Emulsion screening tests, corefloods and flow visualization experiments using an alpha olefin sulfonate (AOS) surfactant with 16 to 18 carbon, Na2CO3 and a heavy Californian crude have shown that alkaline steam foam offers significant advantages over regular steam foam by combining the benefits of thermal and chemical enhanced oil recovery (EOR) processes. Firstly, Na2CO3 reduces surfactant consumption by adsorption by rendering the clay surface more negatively charged. Secondly, by precipitating divalent ions that get ion-exchanged off the clays, Na2CO3 reduces surfactant consumption by precipitation. Thirdly, a suitably formulated alkali-surfactant system reduces the oil-water interfacial tension (IFT) sufficiently to enable the heavy oil to be emulsified into the aqueous phase in the presence of steam. This oil-in-water emulsion is less viscous than that of the oil and can be readily transported. Consequently, the residual oil saturation is reduced to that below steam. Fourthly, this lower residual oil saturation reduces the destabilizing effect of oil on foam resulting in stronger steam foam that provides better mobility control than regular steam foam. Therefore, it has the potential to further reduce steam gravity override. Fifthly, the reduction in gravity override also reduces loss of heat to the cap rock. Steam utilization is thereby improved. When applied to steam drive, cyclic steam soaks and steam-assisted gravity drainage (SAGD) processes, alkaline steam foam has the benefits of increasing foam propagate rate, improving mobility control, improving steam utilization and reducing the residual oil saturation. In the cases of steam soaks and SAGD, it also increases the gravity drainage rate of oil by reducing the effective oil viscosity through emulsification.

This paper presents a systematic study of the effect of surfactant partitioning between supercritical CO2 and water on surfactant transport and foam propagation during two-phase flow. A series of corefloods were conducted on Silurian dolomite cores with different non-ionic and anionic surfactants that represent respective wide ranges of partition coefficients and solubility in supercritical CO2. Foam robustness and displacement efficiency were related to these surfactant properties. Coreflood results and all measured surfactant properties were used in a commercial reservoir simulator to determine the variation of surfactant partitioning effect from laboratory to field scale. Optimization of surfactant partition coefficient for field-scale foam process was performed with different injection strategies.The results from this study enable us to tailor properties of CO2 soluble surfactants (i.e. partition coefficient) to a wide range of reservoir conditions and optimal injection strategies. The understanding of surfactant partitioning effect is also important in overcoming technical challenges encountered in the injection of surfactant in CO2.The partition between CO2 and water phases was much more sensitive to surfactant structure than temperature and pressure. Strong foam development was observed for all non-ionic and anionic surfactants while an increase in surfactant partition coefficient lowers the rate of foam propagation. Field-scale foam simulations indicate that foam performance and surfactant transport was governed not only by constrained injection strategies, but also surfactant partition coefficient. For a given injection strategy, the latter could be optimized to improve injectivity and sweep efficiency.The optimal partition of the surfactant between the CO2 and aqueous phases minimize wasting expensive surfactant in water that is never contacted with CO2. This novel CO2 soluble surfactant concept diversifies injection strategies with respect to operational constraints, broadening the application of foam process.

In a layered 2-D heterogeneous sandpack with 19:1 permeability contrast that was preferentially oil-wet, the recovery by waterflood was only 49.1% of original oil-in-place (OOIP) due to injected water flowing through high-permeability zone leaving low-permeability zone unswept. In order to enhance oil recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT) and consequently enabled gravity and capillary pressure driven vertical counter-current flow to occur and exchange fluids between high- and low-permeability zones during a 42-day system shut-in. Cumulative recovery after a subsequent foamflood was 94.6% OOIP even though foam strength was weak. Recovery with chemical flood (incremental-recovered-oil/waterflood-remaining-oil) was 89.4%. An alternative method is to apply foam mobility control as a robust viscous force dominant process with no initial surfactant injection and shut-in. The light crude oil studied in this paper was extremely detrimental for foam generation. However, the addition of lauryl betaine to NI at a weight ratio of 1:2 (NI: lauryl betaine), made the new NIB blend a good foaming agent with and without the presence of the crude oil. NIB by itself as an IFT reducing and foaming agent is shown to be effective in various secondary and tertiary alkaline/surfactant/foam (ASF) processes in water-wet 1-D homogeneous sandpacks, and in an oil-wet, heterogeneous layered system with 34:1 permeability ratio.

The use of gas for mobility control in chemical enhanced oil recovery is an attractive option to substitute polymer in conditions where its application is not feasible. Especially in carbonate reservoirs, which generally have low permeability and contains vugs and fractures, the use of polymer may result in the loss of permeability and benefits of chemical conformance control. In such conditions, gas is a good alternative. The direct dependence of dispersed gas mobility on rock permeability reduces the likelihood of gas plugging oil-rich low permeable rock matrix in carbonate reservoirs. The mobility of both gas and liquid phases in fractures can be controlled by changing fractional gas and liquid rates in such a manner that the two phases retains their flow characteristics. A series of high performance surfactant-gas corefloods were performed on different core samples having very low to medium permeability values. In each experiment, foamed chemical slug was chased by foamed drive. The main objective of the research work was to determine mobility control characteristic of dispersed flow by evaluating pressure response and oil recovery data obtained from corefloods. All corefloods resulted in oil recoveries above 75% of residual oil to waterflood. No early surfactant and gas breakthrough was observed, indicating absence of viscous fingering and presence of effective mobility control. The scaled pressure gradients remained within the practical limits observed in field EOR applications. Particularly, low pressure gradients observed at relatively high fluid rates indicates a degree of in-situ foaming for favorable injectivity, thus highlighting the potential use of gas in low permeability reservoirs. The beneficial effect of trapped surfactant mobilization on foaming, with the decrease in salinity, was observed in the form of increased foam strength during the drive injection phase. The experimental study provides an insight into the effective application of gas in chemical floods in problematic carbonate formations. Substituting polymer with gas increases the applicability of chemical EOR methods in different types of reservoirs.

Several commercially available, non-ionic surfactants have been identified that are capable of dissolving in CO2 in dilute concentration at typical MMP conditions and, upon mixing with brine, stabilizing CO2-in-water or CO2-in-brine emulsions or foams. These surfactants include water-soluble branched alkylphenol ethoxylates, linear alkylphenol ethoxylates, and branched alkyl ethoxylates. At 25 °C, the solubility of these surfactants in liquid CO2 at ~1300 psia (~9 MPa) is 0.02 – 0.10 wt%. When equal volumes of liquid CO2 and brine (5wt% NaCl) are mixed with these surfactants, an opaque, white emulsion forms that initiallyfills the entire high pressure view cell. This emulsion collapses, yielding a clear aqueous zone below the emulsion as the brine drains from the continuous films of surfactant-stabilized brine that separate the cells of dense CO2, and a clear CO2 zone above the emulsion as the droplets of CO2 coalesce. The stability of these emulsions, as measured by the rate of their collapse, is strongly influenced by the architecture of the surfactant. The most stable emulsions were achieved with water-soluble, branched alkylphenol ethoxylates, such as nonylphenol ethoxylates with 9-15 ethylene oxide repeat units, and linear alkylphenol ethoxylates, which yielded CO2-in-brine emulsions containing 9-23vol% brine that were stable for more than five hours.