Foam Apparent Viscosity Research Articles

Predicting and optimizing CO2 foam performance for enhanced oil recovery: A machine learning approach to foam formulation focusing on apparent viscosity and interfacial tension

Carbon dioxide foam injection stands as a promising method for enhanced oil recovery (EOR) and carbon sequestration. However, accurately predicting its efficiency amidst varying operational conditions and reservoir parameters remains a significant challenge for conventional modeling techniques. This study explores the application of machine learning (ML) methodologies to develop a robust model for matching experimental values in CO2 foam flooding scenarios. Leveraging a comprehensive dataset encompassing diverse surfactants and rock types, with varied porosity and permeability, our model demonstrates accurate predictions across a wide spectrum of conditions. By focusing on key parameters such as foam apparent viscosity, interfacial tension (IFT), injected foam volume, initial oil saturation, porosity, and permeability, we unveil the pivotal role of these factors in determining CO2 foam EOR performance. Through rigorous analysis, we identify the relative importance of each input parameter, with injected foam volume, apparent viscosity, and IFT emerging as dominant factors. The most accurate model was deep neural network (DNN) (R2 value of 0.99). Higher foam viscosity and lower IFT were found to significantly enhance oil recovery rates, though their effects plateau beyond certain thresholds (apparent viscosities above 1200 cP and IFT values below 0.2 mN/m). The findings underscore the potential of ML-driven approaches in enhancing CO2 foam EOR predictions, offering insights crucial for optimizing foam flooding performance across diverse reservoir settings.

Hydroxysulfobetaine foamer for potential mobility control application in high-temperature and ultra-high salt reservoirs

A good foamer should have good solubility in the formation of water, strong foaming ability, and also meet the requirements of thermal stability and low adsorption capacity under high temperature and high salinity conditions. The foam properties of hydroxylsulfobetaine surfactant with different carbon chain lengths were measured at 130 °C, 30 MPa, and in brine with a salinity of 22 × 104 mg·L−1. The results showed that hydroxylsulfobetaine surfactant with long carbon chains exhibited strong foam stability, with foam decay half-lives reaching 13 days for 0.4 wt% EHSB (erucamide propyl hydroxysulfobetaine) and 2.9 days for 0.4 wt% HSB18 (octadecyl dimethyl hydroxypropyl sulfobetaine), respectively. Hydroxysulfobetaine surfactant with short carbon chains had a foam decay half-life of less than 10 h. Considering the poor thermal stability of EHSB at 130 °C, HSB18 was primarily chosen as the foamer. HSB18 and HSB12 (dodecyl dimethyl hydroxypropyl sulfobetaine) were combined in a ratio of 3:1 to form the compound hydroxysulfobetaine MHSB31, which demonstrated good solubility in saline solution with KP (Krafft point) lower than 30 °C. The evaluation, using different concentrations of MHSB31, showed that the foam decay half-life ranged from 88 h for 0.03 wt% MHSB31 compared to 42 h for 0.1 wt% MHSB31. The excellent foaming performance of the compound system is attributed to its high surface dilational modulus and the formation of wormlike micelles. The adsorption capacity test demonstrated that when the concentration was less than 1 wt%, the adsorption capacity of MHSB31 on quartz sand surface was less than 1 mg·g−1, satisfying oilfield requirements. The results of the flow experiment at 130 °C and 10 MPa, in brine with a salinity of 22 × 104 mg·L−1, show that when the concentration of MHSB31 is greater than 0.1 wt%, the foam formed in the core with permeability of 632 mD and 2005 mD has a higher apparent viscosity and resistance factor. Additionally, the relative mobility of the foam formed in the core with a permeability of 2005 mD is lower than that formed in the core with a permeability of 632 mD. This indicates a certain selective reduction effect on mobility. Due to the influence of ultimate capillary pressure, both foam resistance factor and apparent viscosity are lower for the 47 mD core injected with different concentrations of MHSB31 ranging from 0.05 wt% to 0.5 wt%. The evaluation data presented in this paper regarding bulk foam and flow foam, using hydroxysulfobetaine surfactant under high temperature, high pressure, and high salinity conditions, have significant guiding significance for selecting and applying foamers in reservoirs with such harsh conditions.

Machine learning prediction and optimization of CO2 foam performance for enhanced oil recovery and carbon sequestration: Effect of surfactant type and operating conditions

Foam flooding handles the challenges of gas injection constituting a high viscosity medium that sweeps oil more efficiently meanwhile creating a barrier that prevents leakage of gas phase. Therefore, it is a promising enhanced oil recovery (EOR) method, simultaneously an efficient carbon dioxide (CO2) storage technology. The foam's performance displays susceptibility to various reservoir and operational parameters. Numerous laboratory experiments would need to be carried out to study foams and find the optimum foam formulation for the given core conditions. Data-driven approaches can be an alternative method to the time-consuming experimental and conventional modeling techniques, which often face challenges to incorporate the effect of important related parameters such as temperature and type of surfactant to the performance of foam. In the current study, machine learning (ML) models were constructed to predict the CO2 foam apparent viscosity in carbonate and sandstone formations focusing on experimental data from the literature for CO2 foams stabilized by different surfactants. Various anionic, cationic, and nonionic surfactants were considered and characterized based on the hydrophilic-lipophilic balance (HLB) number. Predictive models were developed using ML algorithms based on the data available for eight key process parameters. Artificial neural networks and extra randomized tree algorithms provided the most precise prediction among the applied algorithms. Various predictions for foam apparent viscosity on hypothetical case studies were made on altered input parameters, enabling CO2 mobility to co-optimize EOR and CO2 sequestration while selecting the optimum surfactant for each case.

Factors Influencing the Rheology of Methane Foam for Gas Mobility Control in High-Temperature, Proppant-Fractured Reservoirs

Gas-enhanced oil recovery (EOR) through huff-n-puff (HnP) is an important method of recovering oil from fracture-stimulated reservoirs. HnP productivity is hampered by fracture channeling, leading to early gas breakthroughs and gas losses. To mitigate these issues, foam-generating surfactants have been developed as a method of reducing injected gas phase mobility and increasing oil recovery. This work investigates foam generation and propagation by a proprietary surfactant blend in high-temperature, high-pressure, high-permeability, and high-shear conditions that simulate the environment of a proppant-packed fracture. Bulk foam tests confirmed the aqueous stability and foaming viability of the surfactant at the proposed conditions. Through several series of floods co-injecting methane gas and the surfactant solution through a proppant pack at residual oil saturation, the effects of several injection parameters on apparent foam viscosity were investigated. The foam exhibited an exceptionally high transition foam quality (>95%) and strong shear-thinning behavior. The foam viscosity also linearly decreased with increasing pressure. Another flood series conducted in an oil-free proppant pack showed that swelling of residual oil had no effect on the apparent foam viscosity and was not the reason for the inversely linear pressure dependency. An additional flood series with nitrogen as the injection gas was completed to see if the hydrophobic attraction between the methane and surfactant tail was responsible for the observed pressure trend, but the trend persisted even with nitrogen. In a previous study, the dependence of foam viscosity on pressure was found to be much weaker with a different foaming surfactant under similar conditions. Thus, a better understanding of this important phenomenon requires additional tests with a focus on the effect of pressure on interfacial surfactant adsorption.

The effect of corrosion inhibitor chemistry on rheology and stability of CO2 and N2 acidic foam under harsh conditions

Utilization of CO2 foam in well-stimulation operations is a realistic practice to reduce carbon emissions by injecting CO2 into subsurface formations. The viscosity and stability of CO2 and N2 acidic foamed fluid is impacted by additives such as corrosion inhibitor and chelating agent and conditions such as pressure. In this study, the apparent foam viscosity was determined using a high pressure - high temperature foam rheometer at a temperature of 150 °C, pressure ranging from 1000–4000 psi, and different shear rates 100-2000 1/s. A foam analyzer was furthermore utilized to characterize foam properties such as foamability, foam stability, and bubble structures at 100 °C and 1000 psi. Different surfactants were used due to their ability to generate stable and viscous foam; Duomeen TTM, Ethoduomeen T13, Armovis VES, and the combination of Duomeen TTM and Armovis VES. Among all surfactants, Duomeen TTM provided the highest foam viscosity with CO2 at both low and high shear rate. Once the surfactant solution was mixed with 1.5 wt% of CI, the foam viscosity dropped sharply. However, the synergic surfactants (i.e., Duomeen TTM and Armovis VES) obtained the highest viscosity once mixed with CI. Also, the effect of CO2 and N2 at different pressures on the viscosity of generated foam was investigated. When the CO2 pressure was raised to 2000 psi, the viscosity of CO2 foam increased by 55% at both low and high shear. In comparison, the N2 foam viscosity increased by 12% at 100 1/s shear rate and by 32% at 1500 1/s. According to the findings, the influence of CI increased as the pH of the foam fluid declined, and thus reduced the foam viscosity. Finally, foam properties such as foamability, foam stability, and bubble structure were determined. N2 foam generated higher foam stability than CO2 foam. The findings of this study can help for a better understanding of the effect of corrosion inhibitor on CO2 and N2 foam viscosity at high temperature and pressure.

The Effect of Multiple Cycles of Surfactant-Alternating-Gas Process on Foam Transient Flow and Propagation in a Homogeneous Sandstone

Summary Years of laboratory studies and field tests show that there is still uncertainty about the ability of foam to propagate deep into a reservoir. Many factors have been identified as potential causes of nonpropagation, the most concerning being the lack of sufficient pressure gradient required to propagate foam at locations far from the point of injection. Most researchers that investigated foam propagation did so by coinjecting surfactant and gas. Coinjection offers limited information about transient foam processes due to limitations in the experimental methods needed to measure foam dynamics during transient flow. Foam injection by surfactant-alternating-gas (SAG) has proven to be more effective and common in field application. Repeated drainage and imbibition cycle offer a more favorable condition for the quick generation of foam. Foam can also be propagated at a lower pressure gradient in SAG mode. The objective of this study is to experimentally investigate how transient foam dynamics (trapping, mobilization, and bubble texture) change with multiple cycles of SAG and also with distance from the point of injection. A pair of X-ray source and receiver, differential pressure transducers, and electrical resistance sensors were placed along a 27-cm long, homogeneous, and high-permeability (KL = 70 md) Berea sandstone core. Foam was then generated in situ by SAG injection and allowed to propagate through the core sample under a capillary displacement by brine (brine injection rate = 0.5 cm3/min, Nca = 3×10-7). By use of a novel analytical method on coreflood data obtained from axial pressure and saturation sensors, we obtained trapped foam saturation, in-situ foam flow rates, apparent viscosities, and inferred qualitative foam texture at different core sections. We then observed the following: (i) Maximum trapped foam is uniform across the core sections, with saturation ranging from 47% to 52%. At the vicinity of foam injection, foam apparent viscosity is dominantly caused by gas trapping. At locations farther away, foam apparent viscosity is dominated by both gas trapping and refinement of foam texture. (ii) Cyclic injection of foam further enhances the refinement of foam texture. (iii) Textural refinement increases foam apparent viscosity as it propagates away from the point of injection. (iv) As the foam strength increases, the average gas flow rate in the core sample decreases from 0.5 cm3/min to 0.06 cm3/min. (v) There is no stagnation of foam as remobilization of trapped gas occurs during each cycle at an average flow rate of 0.002 cm3/min.

Effects of Different Types of Stabilizers on the Properties of Foam Detergent Used for Radioactive Surface Contamination.

Compared with high-pressure water and reagent washing decontamination, foam decontamination has a promising application due to its ability to significantly reduce the volume of radioactive waste liquids and effectively decontaminate the inner surface of the pipes, the interior of the large cavities, and the vertical walls. However, the foam is less stable, leading to a low decontamination rate. Currently, three main types of stabilizers with different stabilizing mechanisms, namely nanoparticles, polymers, and cosurfactants, are used to improve foam stability and thus increase the decontamination rate. Nanosilica (NS), xanthan gum (XG), and n-tetradecanol (TD) were used as typical representatives of nanoparticles, polymers, and cosurfactants, respectively, to improve the stability of the foam detergent with pH < 2 and chelating agents. The differences in the effects of these three types of stabilizers on foam properties were investigated. Although NS, XG, and TD all increase the half-life of the foam from 7.2 min to about 40 min, the concentration of TD is much lower than that of NS and XG in the foaming solution, and TD foaming solution has the highest foaming ratio. Moreover, TD can markedly lower the surface tension, resulting in a significant reduction of the wetting contact angle on the surfaces of glass, ceramic tile, stainless steel, and paint, while NS and XG cannot signally change the surface tension and have no obvious effect on the wetting contact angle. At low shear rates, TD can increase the apparent viscosity of foam by two orders of magnitude, and the wall-hanging time of the foam on the vertical wall is more than 30 min. In contrast, NS and XG cause a limited increase in the apparent viscosity of the foam, and the wall-hanging times are both less than 5 min. In addition, TD foaming solution has excellent storage stability, and the storage time has no obvious effect on the performance of the foam. And after only three days of storage, NS undergoes severe agglomeration and precipitation in the foaming solution, resulting in a complete loss of the stabilizing effect. After 90 days of storage, the half-life of XG foam decreases by 26%. For simulated radioactive uranium contamination on both horizontal and vertical surfaces, TD can significantly improve the decontamination rate, especially for vertical surfaces, where TD can increase the single decontamination rate by more than 50%.

Investigation of amine-based surfactants for foamed acid stimulation at high temperature, pressure, and salinity

This research investigated the rheology of foamed acid using different amine-based surfactants including Duomeen TTM (TTM), Ethoduomeen T/13 (T/13), Ethomeen C/12 (C/12), and Armogel O at 150 °C and 1000 psi using a modified (high pressure-high temperature) HPHT foam rheometer. The study was conducted in high-salinity water as a replacement for freshwater to promote sustainability. Foam properties such as foam stability, foamability, foam structure, bubble count, and size were investigated through a novel HPHT foam analyzer under different conditions; (23 °C, 14.7 psi) and (120 °C, 1000 psi). The obtained results showed that Duomeen TTM exhibited the highest foam viscosity as a result of the generation of stable wormlike micelles at 150 °C and 1000 psi. Additionally, both Duomeen and Ethoduomeen T/13 displayed stable foam viscosity at a steady shear rate of 500 1/s for 8 h. The temperature has a major impact on foam viscosity; as the temperature raised from 100 °C to 150 °C, the apparent foam viscosity dropped by 36.9% at 500 1/s and at least by 26.5% at 2000 1/s. The outcomes of the HPHT foam analyzer showed that the surfactants, except for Ethomeen C/12, showed poor foamability under ambient conditions. However, at HPHT, high bubbles count was generated with a uniformly fine texture. For Duomeen TTM, the initial bubble count increased, almost by 76.7%, indicating better foamability at HPHT. Additionally, the foam half-life time of all surfactants except for Duomeen TTM decreased sharply once pressure and temperature increased. The stability decreased by 9.7% for Duomeen TTM, 57.7% for Armogel O, 69.1% for Ethoduomeen T/13, and 85.7% for Ethomeen C/12 as compared to ambient conditions. This paper offers a wide-ranging understanding of amine-based surfactants on stimulating foam viscosity and stability at HPHT.

Shale gas transport in nanopores with mobile water films and water bridge

Gas flow properties in nanopores are significantly determined by the flow patterns. Slug flow pattern is a potential water–gas two phase flow pattern, in which gas molecules flow in form of gas slugs and water molecules separate gas slugs. Considering water slippage, a portion of water molecules accumulates at the wall with lower mobility, while the remaining water molecules take the shape of a water bridge. Adopting foam apparent viscosity model to represent slug rheological behavior, how water bridge disturbs on gas flow capacity is estimated. The results are compared with the water–gas two phase flow model that assumes annular flow pattern as well as the single gas flow model without the consideration of water. The comparison illustrates that gas molecular movement is significantly hindered by flow space reduction and loss of gas slippage. The impact from water phase of slug flow pattern is more significant than that of annular flow pattern on gas flow capacity. It is discovered that larger nanopores improves gas flow capacity while maintaining bulk water layer thickness and increasing water bridge thickness tend to reduce gas transport ability. A better understanding of the structure and transport of water and gas molecules are conducive to figure out the specific gas–water flow behavior and predict shale gas production.

Rheology of oil-based nitrogen foam at shallow reservoir conditions: Experiment and evaluation

Exhibiting as a combination of viscous, elastic, and plastic behavior, rheology is a branch of physics and is majorly concerned with continuum mechanics for flow characterizations, particularly non-Newtonian flow like foam. However, most existing studies of foam rheology are primarily focused on water-based foam, while oil-based foam rheology lacks adequate understanding, plus few comprehensive experimental analyses have been done. This study, for the first time, investigates the rheological behavior of oil-based nitrogen foam with full foam quality and shallow reservoir conditions through a newly-designed visualized capillary rheometer. Basically, the effects of foam quality and shear rate on foam morphology and apparent viscosity were elucidated, and the foam rheology at different temperatures and pressures was evaluated. More specifically, with increasing shear rate, the apparent viscosity of nitrogen foam decreases in a concave-down parabola pattern. With the foam quality of 86 %, the apparent viscosity of the foam flow is found to reach its maximum value, 58.4 mPa·s, at the flow rate of 4 mL/min, temperature of 25 °C and pressure of 5 MPa. The foam flow gradually becomes uniform and dense and the apparent viscosity elevates with increasing foam quality up to 86 %. After that, the foam flow tends to be slug flow and its stability becomes worse with linearly-decreasing apparent viscosity. With increasing pressure, the apparent viscosity and consistency coefficient increase, which result in the increase of rheological index and decrease of non-Newtonian property. The temperature effects on the foam flow are absolutely opposite but stronger in comparison to pressure effects as aforementioned. In addition, the rheological equations of nitrogen foam are determined by fitting the consistency coefficient and rheological index with foam quality. Overall, thorough investigations of the rheology of oil-based nitrogen foam would be of great importance for foam theory and practice.

Effects of different gases on the performance of foams stabilized by Cocamidopropyl betaine surfactant and silica nanoparticles: A comparative experimental study

Application of CO 2 gas in foam enhanced oil recovery (EOR) processes has emerged as a win-win strategy for achieving higher oil recovery factor and reducing greenhouse gas emission, which can significantly help the protection of the ozone layer from depletion. However, lower stability of CO 2 -foam, as compared to the N 2 - and CH 4 -foams, has tempted us to examine combinations of CO 2 with these gases to not only improve the stability of the produced foam but also have CO 2 as the gaseous phase of the foam. In this study, we investigated the effect of different gases and the mixture thereof on the performance of foams in EOR while the aqueous phase of foams is a constant mixture of Cocamidopropyl betaine surfactant (0.03 wt %) and silica nanoparticle (0.1 wt%). To this end, seven different gases, including N 2 , CO 2 , CH 4 , 80% N 2 + 20% CO 2 , 80% CH 4 + 20% CO 2 , 50% CH 4 + 50% CO 2 , 50% N 2 + 50% CO 2 were used as the gases phase for foam generation, and the performance of the produced foams were examined through the following experiments: bulk foam stability tests, apparent foam viscosity measurements, and core flooding tests. The results of foam stability tests showed that half-life time for the CO 2 -, CH 4 -, and N 2 -foams are 13.5, 17.0, and 44.0 min, respectively. Also, as revealed from apparent viscosity measurements, the N 2 - and 80% N 2 +20% CO 2 foams have higher apparent foam viscosity values followed by 50% N 2 +50% CO 2 foam. Furthermore, we showed that a combination of 80% N 2 + 20% CO 2 as the gaseous phase for foam generation could not only improve CO 2 -foam stability, as compared to other foams, but also can substantially increase ultimate oil recovery (56.6 %OOIP), even more than that for N 2 foam (48.6 %OOIP), obtained from core flooding experiments.

Foam-in-Vein: Characterisation of Blood Displacement Efficacy of Liquid Sclerosing Foams.

Sclerotherapy is among the least invasive and most commonly utilised treatment options for varicose veins. Nonetheless, it does not cure varicosities permanently and recurrence rates are of up to 64%. Although sclerosing foams have been extensively characterised with respect to their bench-top properties, such as bubble size distribution and half-life, little is known about their flow behaviour within the venous environment during treatment. Additionally, current methods of foam characterisation do not recapitulate the end-point administration conditions, hindering optimisation of therapeutic efficacy. Here, a therapeutically relevant apparatus has been used to obtain a clinically relevant rheological model of sclerosing foams. This model was then correlated with a therapeutically applicable parameter-i.e., the capability of foams to displace blood within a vein. A pipe viscometry apparatus was employed to obtain a rheological model of 1% polidocanol foams across shear rates of 6 s-1 to 400 s-1. Two different foam formulation techniques (double syringe system and Tessari) and three liquid-to-gas ratios (1:3, 1:4 and 1:5) were investigated. A power-law model was employed on the rheological data to obtain the apparent viscosity of foams. In a separate experiment, a finite volume of foam was injected into a PTFE tube to displace a blood surrogate solution (0.2% w/v carboxymethyl cellulose). The displaced blood surrogate was collected, weighed, and correlated with foam's apparent viscosity. Results showed a decreasing displacement efficacy with foam dryness and injection flowrate. Furthermore, an asymptotic model was formulated that may be used to predict the extent of blood displacement for a given foam formulation and volume. The developed model could guide clinicians in their selection of a foam formulation that exhibits the greatest blood displacement efficacy.

Methane foam performance evaluation in water-wet unconsolidated porous media: A systematic experimental investigation at elevated pressure and temperature conditions

In the petroleum industry, enhanced oil recovery (EOR) techniques employ foam extensively to establish conformance control in heterogeneous and fractured reservoirs in order to increase the sweep efficiency. In such applications, foam performance evaluation under complex subsurface conditions is pivotal for the effective and optimized deployment of foam treatment. However, there is a scarcity of hydrocarbon gas foam generation and evaluation studies that examine the relationships between foam performance and the critical foam parameters at high-pressure and high-temperature conditions.This study aims at methodically investigating the effects of several foam parameters on methane foam performance in water-wet proppant packs under harsh operating conditions. This is in relation to the technical needs of hydrocarbon foam injection into hydraulically-induced, propped fractures in unconventional oil reservoirs. To this end, a state-of-the-art experimental foam generation apparatus was designed, fabricated, and commissioned. We performed a large number of foam flow experiments on proppant packs using methane gas and different foaming agents at 3500 psi and 115 °C. Anionic and amphoteric surfactants were employed to probe the effect of their ionic nature on foam performance. Foam performance sensitivities to various foam generation parameters and operating conditions, such as surfactant concentration, gas fraction, total injection rate, operating pressure, salinity, and proppant pack length were investigated. To this end, steady-state pressure drops across the proppant packs during foam generation and foam's apparent viscosity were measured to quantify the foam performance of surfactants. The results were then analyzed to determine optimum values of the foam parameters and the interplay between these parameters are discussed here. The systematic results achieved from this work are in agreement with the trends available in the literature and provide new insights into complexities of in situ foam generation in water-wet, unconsolidated porous media at extreme reservoir conditions.

Laboratory study on the rheology properties of nanoparticle-stabilized supercritical CO2 foam

Adding nanoparticles (NPs) into surfactant solution has been widely employed in improving foam stability in CO2 Enhanced Oil Recovery (EOR) applications. To help understand the foam flow characteristics in porous media, the rheology behavior of the NP-stabilized CO2 foam is experimentally investigated in this paper. The foam fluid is treated as a non-Newtonian fluid obeying the power law constitutive equation, and the effect of CO2 phase state, oil presence as well as solution salinity on the power law index, and the apparent viscosity of the NP-stabilized foam is scrutinized. Different rheology behavior between the NP-stabilized gaseous CO2 foam and the supercritical CO2 (ScCO2) foam is revealed in the both power law index and the apparent viscosity results. The NP-stabilized gaseous CO2 foam shows the rheology transition behavior from shear thickening to shear thinning with increasing shear rates and supplies maximal foam apparent viscosity of 27.7 mPa s, whereas the NP-stabilized ScCO2 foam shows the universal shear thickening behavior in the studied shear rate range with much higher maximum apparent viscosity of 95.8 mPa s. It is found the apparent viscosity of the NP-stabilized ScCO2 foam could reach up to 210.9 mPa s under the oil presence conditions, while 5 wt% NaCl existence in the aqueous solution could result in slightly lower apparent viscosity of 80.3 mPa s.

Unsteady-State CO2 Foam Generation and Propagation: Laboratory and Field Insights

This work presents a multiscale experimental and numerical investigation of CO2 foam generation, strength, and propagation during alternating injection of surfactant solution and CO2 at reservoir conditions. Evaluations were conducted at the core-scale and with a field-scale radial simulation model representing a CO2 foam field pilot injection well. The objective of the experimental work was to evaluate foam generation, strength, and propagation during unsteady-state surfactant-alternating-gas (SAG) injection. The SAG injection rapidly generated foam based upon the increased apparent viscosity compared to an identical water-alternating-gas (WAG) injection, without surfactant. The apparent foam viscosity of the SAG continually increased with each subsequent cycle, indicating continued foam generation and propagation into the core. The maximum apparent viscosity of the SAG was 146 cP, whereas the maximum apparent viscosity of the WAG was 2.4 cP. The laboratory methodology captured transient CO2 foam flow which sheds light on field-scale CO2 foam flow. The single-injection well radial reservoir simulation model investigated foam generation, strength, and propagation during a recently completed field pilot. The objective was to tune the model to match the observed bottom hole pressure data from the foam pilot and evaluate foam propagation distance. A reasonable match was achieved by reducing the reference mobility reduction factor parameter of the foam model. This suggested that the foam generated during the pilot was not as strong as observed in the laboratory, but it has propagated approximately 400 ft from the injection well, more than halfway to the nearest producer, at the end of pilot injection.

CO2 Foam Behavior in Carbonate Rock: Effect of Surfactant Type and Concentration

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.

Experimental study of rheological behavior of foam flow in capillary tubes

• Rheological behavior of the pre-generated foam was studied in capillary tubes • Tube materials were: PTFE and FEP (hydrophobic) and glass tubes (hydrophilic) • Foam behaves as shear-thinning fluid in all capillary tubes • Transition foam quality in tubes depends on the material type and tube diameter • Foam's apparent viscosity is higher in hydrophobic tubes than in hydrophilic tube due to wall-slip velocity • Wall-slip velocity depends on the tube material type and diameter • Foam texture in tubes is highly dependent on foam quality and flow rate Studies of foam flow in highly permeable porous media are still limited due to foam's complex behavior and discrepancies in foam research. Specifically, it is still unclear how foam flows in capillary tubes and what the effects of material and tube diameter are. We have investigated the rheology of pre-generated foam in capillary tubes. Experiments were carried out using two types of capillary tubes: hydrophobic (PTFE – polytetrafluoroethylene; FEP – fluorinated ethylene propylene) and hydrophilic (GT – glass tubes). The foam was previously formed in the sand-pack by co-injecting a surfactant solution and nitrogen gas. We investigated the effect of material and tube size on foam rheology versus gas fraction (for a fixed flow rate) and flow rate (for a fixed gas fraction). A three-parameter Herschel-Bulkley model was used to describe foam rheology in capillary tubes. Pictures of foam flow in GT and FEP tubes were taken to determine the mean bubble area using image analysis. We estimated wall-slip velocity in capillary tubes and compared the results with the bulk-foam rheology using an analytical expression of the Herschel-Bulkley model for volumetric flow through the circular tubes. We observed shear-thinning behavior in all capillary tubes (FEP, PTFE, GT), and the Herschel-Bulkley model successfully fitted its behavior. The foam in PTFE tubes behaved as a yield-stress fluid, while yield stress was not observed in GT and FEP tubes. We also found that transition foam quality depends on the material type and tube diameter. The results show that foam's apparent viscosity is higher in hydrophobic tubes (FEP and PTFE tubes) than in hydrophilic glass tubes. This was explained by the wall-slip velocity being higher in glass tubes than in FEP and PTFE tubes because of the difference in surface roughness. The corrected flow rate without wall slip matches the flow rate calculated using the measured bulk foam viscosity better. Therefore we conclude that considering wall-slip velocity is important when studying foam flow in porous media.

Mechanistic modeling and measurement of foamed gas flow resistance in fractures

Geologic heterogeneity is one of the important factors controlling migration and distribution of nonaqueous phase liquids in the subsurface. Heterogeneity, such as fractures, complicates the effectiveness of environmental remediation, and uncharacterized aquifer heterogeneity causes significant uncertainties in the removal of nonaqueous phase liquids. Foaming an injection gas is an effective method to alleviate the challenges in accessing heterogeneous media during remediation processes because foam is nonNewtonian and redirects gas and liquid flow. Foamed gas may also assist in increasing the storage of carbon dioxide in saline formations. This paper investigates foam flow behavior in microscale fractures and develops a mechanistic transient foam flow model using the population balance method. Microscale experiments in fractures with apertures of 25 and 88 μm are used to validate the model for pressure drop, gas saturation, and bubble texture. Key differences related to modeling foam in fractures are the potential for continuously varying gas–liquid curvature in fractures and the relationship of this curvature to apparent foam viscosity. Incorporation of a local foam flow resistance factor is important to representing flow physics accurately. Hence, the results of this study provide foundational understanding for upscaling foam rheology in different sized fractures to ensure successful operations in soil/aquifer remediation and CO2 storage in saline formations.

Pore-scale bubble population dynamics of CO2-foam at reservoir pressure

The flow of CO2 foam for mobility control in porous media is dictated by the foam texture, or bubble density, which is commonly expressed as the number of bubbles per unit of flowing gas. In most high-pressure laboratory studies of foam in porous media, the local foam texture cannot be determined due to opaque flow systems. Here, we unlock real-time foam texture dynamics at high pressure (100 bar) by utilizing a realistic pore network with an extended field of view. We identified snap-off as the dominant foam generation mechanism, with additional fining of foam texture caused by backward foam propagation. Foam coalescence during continuous CO2 injection resulted in large gas channels parallel to the general flow direction that reduced the overall foam apparent viscosity. A large fraction of the CO2 foam remained trapped (Xt > 0.97) and stationary in pores to divert CO2 flow and increase sweep efficiency. The gas mobility was calculated from the fraction of trapped bubbles at the pore-scale, and the apparent foam viscosity agreed with similar injection test performed at core-scale. Hence, improved understanding of CO2 foam texture evolution (nf) can strengthen the validation of numerical foam models for upscaling of flow phenomena, instrumental in the development of field scale implementation of CO2 foam for in carbon utilization and storage applications.

A micro-scale rheometer to study foam texture and flow resistance in planar fractures.

We designed and fabricated a new microfluidic device to better enable study of foam microstructure and rheology in planar fractures. The design phase included stress-strain finite element analysis to enhance the pressure tolerance of the device. The optimized design is a 2 cm wide by 7.75 cm long rough fracture that includes 25 posts to anchor the glass cover plate. The posts simulate asperities and provide structural support during bonding of a glass cover plate to the device. Importantly, the new design illustrates improved ability to sustain large differential pressure compared to previous designs in the literature. The rheometer permits study of the relationship among foam bubble morphology, pressure drop, and flow rates. Our findings validated the previous, sparse microvisual studies mentioned in the literature and confirmed that small quality foam, ranging from 20 to 50% gas by volume, contains dispersed bubbles separated by liquid lenses. In this range, the distribution of bubble sizes was roughly 80-90% small uniform bubbles and only 10-20% of larger and more elongated bubbles. Additionally, our studies reveal that foam apparent viscosity is a strong function of foam quality, velocity, and texture (i.e., bubble size). Apparent viscosity of foam ranged from 100 to 600 cP for the conditions studied. High quality foams in fractures are independent of gas flow rates but very sensitive to liquid flow rates. On the other hand, low quality foams are sensitive to gas flow rates but independent of liquid flow rates.