Foam is a promising means to assist in the permanent, safe subsurface sequestration of CO₂, whether in aquifers or as part of an enhanced-oil-recovery (EOR) process. Here we review the advantages demonstrated for foam that would assist CO₂ sequestration, in particular sweep efficiency and residual trapping, and the challenges yet to be overcome. We also review the research and field-trial literature on CO₂ foam sweep efficiency, capillary gas trapping in foam, issues involved in surfactant selection for CO₂ foam applications, foam field trials, and the state of the art from laboratory and modelling research on CO₂ foam properties, in order to present the prospects and challenges for foam-assisted CO₂ sequestration. Challenges to foam-assisted CO₂ sequestration include the following: 1) verifying the advantages indicated by laboratory research at the field scale 2) optimizing surfactant performance, while further reducing cost and adsorption if possible 3) long-term chemical stability of surfactant, and dilution of surfactant in the foam bank by flow of water. Residual gas must reside in place for decades, even if surfactant degrades or is diluted. 4) optimizing injectivity and sweep efficiency in the field-design strategy.

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This paper discusses axi-symmetric flow during CO₂ injection into a non-adiabatic reservoir accounting for Joule-Thomson cooling and steady-state heat exchange between the reservoir and the adjacent layers by Newton's law. An exact solution for this 1D problem is derived and a new method for model validation by comparison with quasi 2D analytical heat-conductivity solution is developed. The temperature profile obtained by the analytical solution shows a temperature decrease to a minimum value, followed by a sharp increase to initial reservoir temperature on the temperature front. The temperature distribution head of the front is determined by the initial reservoir temperature, while the solution behind the front is determined by the temperature of injected CO₂. The analytical model exhibits stabilisation of the temperature profile and the cooled zone. The explicit formula for temperature distributions allows determining the maximum injection rate that avoids hydrate formation.

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The success of CO2 storage projects largely depends on addressing formation damage, such as salt precipitation, hydrate formation, and fines migration. While analytical models for reservoir behaviour during CO2 storage in aquifers and depleted gas fields are widely available, models addressing formation damage and injectivity decline are scarce. This work aims to develop an analytical model for CO2 injection in a layer-cake reservoir, considering permeability damage. We extend Dietz’s model for gravity-dominant flows by incorporating an abrupt permeability decrease upon the gas-water interface arrival in each layer. The exact Buckley-Leverett solution of the averaged quasi-2D (x, z) problem provides explicit formulae for sweep efficiency, well impedance, and skin factor of the injection well. Our findings reveal that despite the induced permeability decline and subsequent well impedance increase, reservoir sweep efficiency improves, enhancing storage capacity by involving a larger rock volume in CO2 sequestration. The formation damage factor d, representing the ratio between damaged and initial permeabilities, varies from 0.016 in highly damaged rock to 1 in undamaged rock, resulting in a sweep efficiency enhancement from 1–3% to 50–53%. The developed analytical model was applied to predict CO2 injection into a depleted gas field.@en

Injection of high-pressure CO2 into depleted gas reservoirs can lead to low temperatures promoting formation of hydrate in the near wellbore area resulting in reduced injection rates. The design of effective mitigation methods requires an understanding of the impact of crucial parameters on the formation and dissociation of CO2 hydrate within the porous medium under flowing conditions. This study investigates the influence of water saturation (ranging from 20 % to 40 %) on the saturation and kinetics of CO2 hydrate during continuous CO2 injection. The experiments were conducted under a medical X-ray computed tomography (CT) to monitor the dynamics of hydrate growth inside the core and to calculate the hydrate saturation profile. The experimental data reveal increase in CO2 hydrate saturation with increasing water saturation levels. The extent of permeability reduction is strongly dependent on the initial water saturation: beyond a certain water saturation the core is fully blocked. For water saturations representative of the depleted gas fields, although the amount of generated hydrate is not sufficient to fully block the CO2 flow path, a significant reduction in permeability (approximately 80 %) is measured. It is also observed that the volume of water + hydrate phases increases during hydrate formation, indicating a lower-than-water density for CO2 hydrate. Having a history of hydrate at the same water saturation leads to an increase in CO2 consumption compared to the primary formation of hydrate, confirming the existence of the water memory effect in porous media.@en

The study aims to quantitatively assess the risk of hydrate formation within the porous formation and its consequences to injectivity during storage of CO₂ in depleted gas reservoirs considering low temperatures caused by the Joule Thomson (JT) effect and hydrate kinetics. The aim was to understand which mechanisms can mitigate or prevent the formation of hydrates. The key mechanisms we studied included water dry-out, heat exchange with surrounding rock formation, and capillary pressure. A compositional thermal reservoir simulator is used to model the fluid and heat flow of CO₂ through a reservoir initially composed of brine and methane. The simulator can model the formation and dissociation of both methane and CO₂ hydrates using kinetic reactions. This approach has the advantage of computing the amount of hydrate deposited and estimating its effects on the porosity and permeability alteration. Sensitivity analyses are also carried out to investigate the impact of different parameters and mechanisms on the deposition of hydrates and the injectivity of CO₂. Simulation results for a simplified model were verified with results from the literature. The key results of this work are: (1) The Joule-Thomson effect strongly depends on the reservoir permeability and initial pressure and could lead to the formation of hydrates within the porous media even when the injected CO₂ temperature was higher than the hydrate equilibrium temperature, (2) The heat gain from underburden and overburden rock formations could prevent hydrates formed at late time, (3) Permeability reduction increased the formation of hydrates due to an increased JT cooling, and (4) Water dry-out near the wellbore did not prevent hydrate formation. Finally, the role of capillary pressure was quite complex, where it reduced the formation of hydrates in certain cases and increased in other cases. Simulating this process with heat flow and hydrate reactions was also shown to present severe numerical issues. It was critical to select convergence criteria and linear system tolerances to avoid large material balance and numerical errors.

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Hydrogen plays a crucial role in the transition to low-carbon energy systems, especially when integrated into energy storage applications. In this study, the concept of exergy-return on exergy-investment (ERoEI) is applied to investigate the exergetic efficiency (defined as the ratio of useful exergy output to invested exergy input) and CO2 equivalent intensity of the hydrogen supply chain, with a specific focus on the underground hydrogen storage process. Our findings reveal that the overall exergetic efficiency of the electricity-to-hydrogen-to-electricity conversion process can reach up to 25 %. Among the hydrogen production methods, green hydrogen, produced via electrolysis powered by renewable energy, exhibits the lowest CO2 equivalent intensity. Blue hydrogen, produced from natural gas with carbon capture, can significantly reduce the carbon footprint of electricity generation, though this advantage comes at the expense of decreased exergetic efficiency. Analysis further indicates that the exergetic efficiency of underground storage components ranges from 72 % to 92 %. A substantial fraction of the exergy is lost during compression and injection of the stored hydrogen. Nevertheless, the subsurface operations contribute a minimal CO2 emission, between 1.46–4.56 grams of equivalent CO2 per megajoule (gr-CO2eq/MJ) when powered by low-carbon energy sources. Furthermore, it is found that hydrogen loss in the reservoir, along with methane and hydrogen leak during surface operations, notably affects the overall efficiency of the storage process.@en

CO2 storage in deep saline aquifers is an effective strategy for reducing greenhouse gas emission. However, salt precipitation triggered by evaporation of water into injected dry CO2 causes injectivity reduction. Predicting the distribution of precipitated salts and their impact on near-well permeability remains challenging. Therefore, a detailed investigation of the interactions between salt precipitation and porous domain is essential for of revealing the mechanisms of pore blockage due to salt crystallization. Through series of microfluidic experiments, direct observations, coupled with detailed imaging processing, form the basis for explaining these phenomena and provide a relationship between water and salt saturations, highlighting the critical roles played by local capillary-driven flow and water film along grains in influencing water relocation. The results reveal two distinct types of salt crystallization: occurring inside the brine with smooth edges and at the CO2-brine interface with rough edges. Furthermore, the impact of local heterogeneity and surface wettability on salt precipitation patterns is discussed. The transition region between the porous domains and inlet/outlet channels exhibits brine backflow and a larger amount of salt accumulation. This paper presents a comprehensive analysis of the dynamic process of salt dry-out occurring during CO2 injection at the pore scale.@en

Carbon dioxide capture and storage in subsurface geological formations is a potential solution to limit anthropogenic CO₂ emissions and combat global warming. Depleted gas fields offer significant CO₂ storage volumes; however, injection of CO₂ into these reservoirs poses some potential challenges for the injectivity, containment and well/facility integrity due to low temperatures caused by isenthalpic expansion of CO₂. A key injectivity risk is due to possible formation of hydrates at the low expected temperatures. This study aims to address main causes of CO₂ hydrate formation and its impact on permeability of porous media. This review highlights the current state of knowledge in the literature while emphasizing the need to bridge existing gaps in derisking CO₂ injection into (depleted) low-pressure gas reservoirs. In summary, according to the existing literature, the potential for hydrate formation is assessed to be credible. Current industry solutions exist to manage this risk; however, they are costly and energy intensive. Future research will be needed to provide capabilities to manage this risk more efficiently.

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Foam is utilized in enhanced oil recovery and CO₂ sequestration. Surfactant-alternating-gas (SAG) is a preferred approach for placing foam into reservoirs, due to it enhances gas injection and minimizes corrosion in facilities. Our previous studies with similar permeability cores show that during SAG injection, several banks occupy the area near the well where fluid exhibits distinct behaviour. However, underground reservoirs are heterogeneous, often layered. It is crucial to understand the effect of permeability on fluid behaviour and injectivity in a SAG process. In this work, coreflood experiments are conducted in cores with permeabilities ranging from 16 to 2300 mD. We observe the same sequence of banks in cores with different permeabilities. However, the speed at which banks propagate and their overall mobility can vary depending on permeability. At higher permeabilities, the gas-dissolution bank and the forced-imbibition bank progress more rapidly during liquid injection. The total mobilities of both banks decrease with permeability. By utilizing a bank-propagation model, we scale up our experimental findings and compare them to results obtained using the Peaceman equation. Our findings reveal that the liquid injectivity in a SAG foam process is misestimated by conventional simulators based on the Peaceman equation. The lower the formation permeability, the greater the error.

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Depleted gas reservoirs are viable choices for large-scale CO₂ storage and to displace remaining methane volumes to further increase the storage capacity (EGR). However, deployment of such projects depends on an informed knowledge of the magnitude of mixing of the miscible gases, efficiency in displacing in-situ methane by CO₂, composition of the produced gas, and CO₂ storage capacity. This study focuses on the fundamental analysis of mixing during CO₂-EGR using a numerical approach. We propose to conduct very fine grid compositional simulations to provide insights into the mixing of CO₂ and methane in a gas reservoir at different reservoir and operational conditions. We first analyze a stratified layer model to understand the basic mechanisms of scale-dependency of dispersion and the significance of reservoir heterogeneity on fluid mixing. To consider more realistic reservoir heterogeneity, a two-dimensional stochastic reservoir model is analyzed to estimate dispersivity generated as fluids flow in porous media at different scales. Reservoir heterogeneity is represented by the Dykstra Parsons coefficient (V_DP) and autocorrelation length, and fluid properties are modeled depending on pressure and temperature conditions. Field-scale simulation is also performed to discuss the way dispersion is modeled in reservoir simulation affects simulated gas recovery. Our study shows that the variance of permeability and convective spreading are the primary causes of fluid mixing at any scale. In addition, molecular diffusion is not always negligible in gas mixing even in large-scale heterogeneous reservoirs since gas has much larger diffusivity than liquid. Furthermore, the mechanism of fluid mixing during CO₂-EGR is complex with the interplay between convective spreading, transverse dispersion (including molecular diffusion), and gravity segregation. Although geoscientists often assume numerical dispersion can represent physical dispersion, our study indicates this is an oversimplification and could cause significant errors in calculated gas recovery. Permeability heterogeneity is essential for the dispersion growth process and the final displacement behavior. Reservoir heterogeneity should be modeled with high-resolution grid models to analyze mixing behaviors more accurately.

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Depleted gas reservoirs are attractive sites for Carbon Capture and Storage (CCS) due to their huge storage capacities, proven seal integrity, existing infrastructure and subsurface data availability. However, CO₂ injection into depleted formations can potentially lead to hydrate formation near the wellbore due to Joule-Thomson cooling, which might cause injectivity issues. Some challenges encountered when modeling and simulating this process are the computational time caused by Newton's convergence issues and instability. The objective of this work is to propose a novel approach for hydrate risk assessment during CO₂ injection into depleted gas reservoirs using physics-based Machine Learning (ML) approach. First, the selection of input parameters for the ML models is performed based on sensitivity study results using an analytical solution for different operational and petrophysical values. Then the ML models are tuned and tested using datasets from numerical reservoir simulation results based on a wide range of input parameter values. To the best of our knowledge, this is the first time that an ML approach is used for risk assessment of CO₂ hydrate in its storage in depleted gas reservoirs. The ML models developed in this study presented an efficient performance to predict hydrate-forming events. The deep neural network model performed best with a 95% recall value and 84% precision value. These results show that the ML model can be further utilized for risk assessment in the screening stage, and the combination of screening by ML, followed by detailed analysis with numerical simulation in high-risk cases can be an efficient probing workflow for future CCS projects.

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Understanding the kinetics of CO2 hydrate formation and the resulting saturation of the hydrate in porous rocks is crucial for processes such as the storage of CO2 in underground formations. Nevertheless, to date, there is no established procedure that utilizes a medical CT scanner for quantifying gas hydrate saturation in core samples during the growth stage. This study proposes a methodology for estimating hydrate saturation using a medical CT scanner during the injection of CO2 into porous media. This method uses the mean area obtained from the image analysis to calculate the dynamic profile of water and the CO2 hydrate along the length of the sandstone core. To demonstrate the technique, core flooding experiments were conducted to form gas hydrates in semibrine-saturated sandstone cores.@en

Hypothesis: Underground hydrogen storage in depleted hydrocarbon reservoirs and aquifers has been proposed as a potential long-term solution to storing intermittently produced renewable electricity, as the subsurface formations provide secure and large storage space. Various phenomena can lead to hydrogen loss in subsurface systems with the key cause being the trapping especially during the withdrawal cycle. Capillary trapping, in particular, is strongly related to the hysteresis phenomena observed in the capillary pressure/saturation and relative-permeability/saturation curves. This paper address two key points: (1) the sole impact of hysteresis in capillary pressure on hydrogen trapping during withdrawal cycles and (2) the dependency of optimal operational parameters (injection/withdrawal flow rate) and the reservoir characteristics, such as permeability, thickness and wettability of the porous medium, on the remaining hydrogen saturation. Model: To study the capillary hysteresis during underground hydrogen storage, Killough [1] model was implemented in the MRST toolbox [2]. A comparative study was performed to quantify the impact of changes in capillary pressure behaviour by including and excluding the hysteresis and scanning curves. Additionally, this study investigates the impact of injection/withdrawal rates and the aquifer permeability for various capillary and Bond numbers in a homogeneous system. Findings: It was found that although the hydrogen storage efficiency is not considerably impacted by the inclusion of the capillary-pressure scanning curves, the impact of capillary pressure on the well properties (withdrawal rate and pressure) can become significant. Higher injection and withdrawal rates does not necessarily lead to a better performance in terms of productivity. The productivity enhancement depends on the competition between gravitational, capillary and viscous forces. The observed water upconing at relatively high capillary numbers resulted in low hydrogen productivity. highlighting the importance of well design and placement.

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Characterizing the wettability of hydrogen (H₂)–methane (CH₄) mixtures in subsurface reservoirs is the first step towards understanding containment and transport properties for underground hydrogen storage (UHS). In this study, we investigate the static contact angles of H₂–CH₄ mixtures, in contact with brine and Bentheimer sandstone rock using a captive-bubble cell device at different pressures, temperatures and brine salinity values. It is found that, under the studied conditions, H₂ and CH₄ show comparable wettability behaviour with contact angles ranging between [25°–45°]; and consequently their mixtures behave similar to the pure gas systems, independent of composition, pressure, temperature and salinity. For the system at rest, the acting buoyancy and surface forces allow for theoretical sensitivity analysis for the captive-bubble cell approach to characterize the wettability. Moreover, it is theoretically validated that under similar Bond numbers and similar bubble sizes, the contact angles of H₂ and CH₄ bubbles and their mixtures are indeed comparable. Consequently, in large-scale subsurface storage systems where buoyancy and capillary are the main acting forces, H₂, CH₄ and their mixtures will have similar wettability characteristics.

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We develop a method based on concept of exergy-return on exergy-investment (ERoEI) to determine the energy efficiency and CO₂ footprint of polymer and surfactant enhanced oil recovery (EOR). This integrated approach considers main surface and subsurface elements of the chemical EOR methods. The main energy investment in oil recovery by water injection is mainly related to circulation of water with respect to exergy of the oil produced. At large water cuts of >90%, more than 70% of the total invested energy is spent on pumping the fluids. Consequently, production of barrels of oil is associated with large amounts of CO₂ emission for mature oil fields with large water cuts. Our analysis shows that injection of polymer increases the energy efficiency of the oil recovery system. Because of additional oil (exergy gain) and less water circulation (exergy investment), the project-time averaged energy invested (and consequently CO₂ emitted) to produce one barrel of oil from polymer flooding is less than that of the water flooding at large water cuts. We conclude that polymer injection into reservoirs with high water cut can be a solution for two major challenges of the transition period: (1) meet the global energy demand via an increase in oil recovery and (2) reduce the CO₂ footprint of oil production (more and cleaner oil). For surfactant-polymer EOR, the extent of improvement in energy efficiency depends on the incremental gain and the simplicity of the formulations.

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This paper introduces new oil recovery mechanisms for oil recovery by polymer injection in heavy oil reservoirs with strong bottom aquifers. Due to unfavorable mobility ratio between aquifer water and oil and the development of the sharp cones significant amount of oil remains unswept. To overcome these issues, for the case demonstrated in this paper, a polymer injection pilot was executed with three horizontal injectors, located a few meters above the oil/water contact. The injectivity issues resulted in frequent shutdowns of the injectors. Interestingly, the water cut reversal and oil gain continued during the shut-in periods. This observation has led to the development of a new cyclic polymer injection strategy, in which the injection of polymer is alternated with intentional well shut-ins. The strategy is referred to as Nothing-Alternating-Polymer (NAP). It was found that during polymer injection, the oil is recovered by conventional mobility and sweep enhancement mechanisms ahead of the polymer front. Additionally, during this stage the injected polymer squeezes the existing cones and creates a barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative effect of the cones or water channels (blanketing mechanism). Moreover, injection of polymer pushes the oil to the depleted water cones, which is then produced by the water coming from the aquifer during shut-in period (recharge mechanism). During the shut-in or NAP period, the aquifer water also pushes the existing polymer bank and hence leads to extra oil production. The resistance caused by polymer adsorption reduces the extent of fingering of water into polymer bank. The NAP strategy reduces polymer loss into aquifer and improves the polymer utilization factor expressed in kg-polymer/bbl of oil, resulting in a favorable economic outcome.

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This paper presents an assessment of the life-cycle exergetic efficiency and CO2 footprint of the underground biomethanation process. The subsurface formation, hosting microorganisms required for the reaction, is utilized to convert CO2 and green (produced from renewable energy) hydrogen to the so-called "green"or synthetic methane. The net exergy gain and CO2 intensity of the biomethanation process are compared to the alternative options of (1) green H2 storage (no energy upgrading process to CH4) and (2) fossil-based CH4 with carbon capture and storage (CCS), i.e., blue CH4. It is found that with the current state of the technology and within the assumptions of this study, the exergy return on the exergy invested for underground biomethanation does not outperform the direct storage and utilization of green H2. The maximum exergetic efficiency of the biomethanation process is calculated to be 15-33% for electricity and 36-47% for heating, while the overall exergetic efficiency of the direct use of H2 for electricity is estimated to be between 20 and 61%. Moreover, the energy produced from the underground biomethanation process has the largest CO2 intensity among the studied options. Depending on the technology used in the CCS and hydrogen production stages, the CO2 intensity of the electricity generated from synthetic CH4 can be as large as 142 g CO2/MJe, which is at least 56-73% larger than those of the two other studied cases.

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An understanding of how CO2 foam flows through a reservoir rock is useful for many subsurface applications, including enhanced oil recovery and CO2 storage. There are economic and environmental benefits in identifying surfactants that exhibit good foaming behavior with CO2 at both low concentrations and high foam qualities. Core flood experiments have been carried out to investigate the behavior of supercritical CO2 foams flowing through a high-permeability Indiana Limestone. The foaming behavior and concentration response of two surfactants, a betaine and a sultaine, were investigated. For the two surfactants, the transition foam quality and the maximum apparent foam viscosity both decreased with reducing surfactant concentration. A comparison between the foaming behaviors of these surfactants with CO2 and N2 was also carried out. It was found that the N2 generated stronger foam at low foam qualities, but the CO2 was better at maintaining good foaming behavior at high foam qualities.

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Foam is a promising means to assist in the permanent, safe subsurface sequestration of CO2, whether inaquifers or as part of an enhanced-oil-recovery (EOR) process. Here we review the advantages demonstratedfor foam that would assist CO2 sequestration, in particular sweep efficiency and residual trapping, and thechallenges yet to be overcome. CO2 is trapped in porous geological layers by an impermeable overburden layer and residual trapping,dissolution into resident brine, and conversion to minerals in the pore space. Over-filling of geologicaltraps and gravity segregation of injected CO2 can lead to excessive stress and cracking of the overburden.Maximizing storage while minimizing overburden stress in the near term depends on residual trapping inthe swept zone. Therefore, we review the research and field-trial literature on CO2 foam sweep efficiencyand capillary gas trapping in foam. We also review issues involved in surfactant selection for CO2 foamapplications. Foam increases both sweep efficiency and residual gas saturation in the region swept. Both propertiesreduce gravity segregation of CO2. Among gases injected in EOR, CO2 has advantages of easier foamgeneration, better injectivity, and better prospects for long-distance foam propagation at low pressuregradient. In CO2 injection into aquifers, there is not the issue of destabilization of foam by contact with oil,as in EOR. In all reservoirs, surfactant-alternating-gas foam injection maximizes sweep efficiency whilereducing injection pressure compared to direct foam injection. In heterogeneous formations, foam helpsequalize injection over various layers. In addition, spontaneous foam generation at layer boundaries reducesgravity segregation of CO2. Challenges to foam-assisted CO2 sequestration include the following: 1) verifying the advantagesindicated by laboratory research at the field scale 2) optimizing surfactant performance, while furtherreducing cost and adsorption if possible 3) long-term chemical stability of surfactant, and dilution ofsurfactant in the foam bank by flow of water. Residual gas must reside in place for decades, even if surfactantdegrades or is diluted. 4) verifying whether foam can block upward flow of CO2 through overburden, eitherthrough pore pathways or microfractures. 5) optimizing injectivity and sweep efficiency in the field-designstrategy. We review foam field trials for EOR and the state of the art from laboratory and modeling research onCO2 foam properties to present the prospects and challenges for foam-assisted CO2 sequestration.

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The efficiency of oil processes depends on the product of volumetric sweep and microscopic sweep. In oil recovery by steam injection the microscopic sweep is generally good; however, obtaining a good volumetric sweep can be challenging. This is caused by low density and viscosity of the injected steam combined with the reservoir heterogeneity, in particular existence of thief zone. Consequently, the steam utilization factor measured by steam-to-oil ratio (SOR, kg steam/bbl of oil) for many steam-flooding projects becomes poor. All these issues can be addressed by a successful application of steam foam technology. In steam foam applications, steam (plus a non-condensing gas) is injected simulateneously with a surfactant solution. Under the favorable injection conditions a foam is formed inside the reservoir leading to significant reduction of steam mobility and can eventually improve sweep efficiency. In the literature many successful steam foam pilots have been reported. However, most of these applications are at relatively shallow reservoirs with low pressures and thus low temperatures. In our paper we investigate if steam foam can also be effectively used for applications at high steam temperatures, significantly exceeding 200°C. To test the viability of steam foam technology at high temperatures, we have tested the stability of multiple surfactants at reservoir conditions. For those surfactants that showed good stability, core flood tests have been carried out to test the ability to form foam and to assess the resulting foam strength. Steam foam tests have also been carried out at temperature up to 240°C.

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