CO2 Foam Research Articles

Investigation of oil-based CO2 foam EOR and carbon mitigation in a 2D visualization physical model: Effects of different injection strategies

CO2 flooding in low-permeability and tight oil reservoirs often encounters gas channeling, which affects oil recovery. To address this, oil-based CO2 foam development is explored using a two-dimensional visual physical model. The study includes three experimental setups: CO2 flooding followed by oil-based CO2 foam flooding, CO2 Huff-n-Puff (HnP) followed by oil-based CO2 foam HnP, and oil-based CO2 foam HnP followed by oil-based CO2 foam flooding. Findings reveal that using oil-based CO2 foam after CO2 development increases recovery factors by 15.62% and 35.86% for HnP and flooding, respectively, and significantly boosts CO2 storage. The CO2 storage is 1.96 times and 6.03 times higher than the initial one. After oil-based CO2 foam is used, the red area near the outlet of the visualization model becomes shallower, indicating a further decrease in residual oil saturation. The oil-based CO2 foam method reduces residual oil saturation and extends production duration while decreasing gas production rates. This approach effectively plugs gas channels, enhancing CO2 sweep efficiency, crude oil mobility, and recovery. The results provide innovative strategies for oilfield development, supporting carbon sequestration and offering substantial economic and environmental benefits.

Preparation of styrene‐phenylamine monomer copolymer nanospheres and its performance for stabilizing CO2 foam

AbstractImproving the stability of CO2 foam is a core concern in CO2 foam flooding oil recovery technology. Using hydrophobic nano‐SiO2 to enhance the stability of CO2 foam is a common approach, but hydrophobic nano‐SiO2 faces challenges, such as easy aggregation, difficult dispersion, and performance needs to improve. In this article, a novel dispersion of styrene‐phenylamine monomer copolymer (PSSN) nanosphere with primary amine groups on the surface was synthesized. The synthesis conditions of PSSN were optimized, and its performance for stabilizing CO2 foam was evaluated. The experimental results demonstrated that PSSN had better performance for stabilizing CO2 foam than that of hydrophobic nano‐SiO2 when using cocamidopropyl betaine (CAB) as the foaming agent. With the CAB concentration of 4000 mg/L and PSSN concentration of 100 mg/L in the brine having salinity of 8460 mg/L, the half‐life of CO2 foam at 90°C was 131 min, which was 43 min longer than that stabilized by hydrophobic nano‐SiO2 under the same conditions. This is for the first time that polystyrene microspheres with amine groups on the surface was used to stabilize CO2 foam. The study provides a new nanoparticle option for stabilizing CO2 foam.

Toxicity and environmental aspects of surfactants

Abstract As the single largest class of specialty chemicals, surfactants are consumed in huge quantities in our daily life and in many industrial areas. In the past, the attention was focused entirely on technical performance. However, starting from the 1970s and 80s, surfactant related environmental concerns have become the main driving force to upgrade surfactant production technology to make more benign or “greener” products. For this reason, environmental issues, dermatological effects, and oral toxicity are the main priorities when surfactants are considered for a specific purpose. In this paper, we present five cases to demonstrate how the surfactant industry tackles these challenges to mitigate the environmental and health effects associated with surfactant consumption. We also discuss the important role played by surfactants in a current carbon capture and storage (CCS) strategy to reduce the CO2 level in the atmosphere. Surfactant-based stable CO2 foam flooding is a well-established enhanced oil recovery technique. It has been considered to be an economically realistic procedure to sequester large amounts of CO2 in geological formations.

CO2 foam structure and displacement dynamics in a Hele–Shaw cell

The substitution of CO2 gas with CO2 foam for improved mobility control has recently attracted research attentions in enhanced oil recovery (EOR) as well as aquifer and soil remediation. However, the interplay between CO2 foam properties and oil displacement remains less investigated. In this work, using clear visualizations, we systematically investigate the dynamic advection-dominated foam morphology, its corresponding viscosity, and the efficiency and dynamics of oil displacement process by CO2 foam in a Hele–Shaw cell under the effects of gas ratio (Rg), fluid injection rates (Qt), and surfactant type. Clear visualization enables particle image velocimetry to calculate actual, rather than nominal, foam velocity that significantly affects the estimated foam viscosity. Our results demonstrate that at elevated gas ratios under constant total injection rate, larger and more uniform bubbles with less number density and greater interfacial area are obtained. Increasing the injection rates leads to finer foam texture at a constant gas ratio. Different foam structures have an impact on the foam viscosity, with a general increasing trend of viscosity for larger bubbles as Rg increases from 0.5 to 0.85. The higher the foam viscosity, the more stable displacement interfaces with less viscous fingers are observed, leading to improved sweeping rates. The green surfactants (saponin + Cellulose NanoFibers) provide foams with higher viscosity and, thus, more stable displacement interfaces. These findings highlight the important effect of Rg–dependent foam structure on its viscosity, which in turn is crucial for controlling the mobility of CO2 foam to maximize oil recovery rate during EOR processes.

Enhanced oil recovery and carbon sequestration in low-permeability reservoirs: Comparative analysis of CO2 and oil-based CO2 foam

Excessive CO2 emissions contribute to global climate change thus mandating effective methods for CO2 utilization and sequestering. In this study, one-dimensional flow simulation experiments on CO2 flooding, CO2 Huff-n-Puff, oil-based CO2 foam flooding, and oil-based CO2 foam Huff-n-Puff are conducted using low-permeability sandstone cores modeled after the Q131 block in Liaohe Oilfield, characterized by porosity ranging from 15% to 20% and permeability between 25 mD to 35 mD. Low permeability reservoirs are rich in oil resources and may effectively sequester CO2. Parameters pertaining to oil and gas production and carbon storage are collected. Nuclear magnetic resonance (NMR) is employed to determine the spatial variation of oil saturation in the cores. The experimental results show 8.03% and 41.21% increase in oil recovery factor by foam flooding and foam Huff-n-Puff relative to CO2 as the recovery agent. Moreover, NMR analysis confirms lower residual oil saturation in core samples using foam, suggesting better displacement agent. Oil-based CO2 foam recovery contributed to effective carbon sequestration, with carbon storage increasing by 34.24% and 315% relative to CO2 flooding and CO2 Huff-n-Puff, respectively. CO2 storage mechanisms for oil-based CO2 foam recovery method are detailed.

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.

A numerical feasibility study of CO2 foam for carbon utilization and storage in a depleted, high salinity, carbonate oil reservoir

Carbon Capture, Utilization, and Storage (CCUS) offers a viable solution to reduce the carbon footprint in the petroleum industry, and foam injection presents a promising method to achieve this while simultaneously increasing oil recovery. In this work, we studied the feasibility of CO2 foam for co-optimizing enhanced oil recovery and CO2 storage in a high-salinity carbonate formation. The simulated hydrodynamic model is a depleted formation containing 30% residual oil, with three mechanisms for CO2 storage: solubility, residual, and mineralization trapping mechanisms. The results showed that after 20 years, oil recovery during foam injection was 2.7 times higher than CO2 injection, and the CO2 stored during foam flooding was 38% higher than CO2 injection. Notably, foam injection also increased CO2 storage capacity by 2.6 times, indicating the potential to store around 2 gigatons of CO2 in the simulated model. This was attributed to the ability of foam to significantly reduce gas mobility and thus form isolated bubbles through its Jamin effect. Residual trapping was the dominant trapping mechanism, contributing to over 70% of the total CO2 trapped, attributed to the reduction in the dissolution of CO2 in brine due to the high salinity of the aqueous medium. CO2 mineralization was also studied, showing the least trapping efficiency and the dissolution trend of all the carbonate minerals. This study illustrates a novel CO2 utilization and storage technique in which CO2 is concurrently sequestered while enhancing oil recovery in a depleted oil reservoir by injecting CO2 as foam. The relevance of this study lies in its potential to provide a dual benefit of reducing greenhouse gas emissions and boosting oil production, offering a sustainable approach for the petroleum industry.

The conformance control and enhanced oil recovery performance of CO2 foam reinforced by regenerated cellulose

CO2 foam flooding is one of the most promising technologies for conformance control and enhanced oil recovery (EOR) in heterogenous tight oil reservoirs. However, it is challenging to maintain foam stability at in-situ high temperature and high salinity reservoir conditions, thus seriously limiting the flooding efficiency. Herein, a new approach of CO2 foam reinforced by regenerated cellulose (RC) was proposed and evaluated by multiple light scattering method and microscopic detection; afterwards, the conformance control and EOR performances were evaluated via flooding experiments at representative reservoir conditions of 85 °C and 59737.6 mg/L, using artificial micro-models and heterogenous core test. Results have demonstrated that: Compared with CO2 foam without RC, the foam with 1 % RC could elongate the foam half-life by ∼30 times (i.e., from 18 to 543 mins) and the drainage half-time by ∼4 times (i.e., from 2.5 to 9.5 mins), respectively; For the conformance control, the CO2 foam flooding with RC improved the sweep efficiency from the respective 42.4 % and 15.8 % to 95.4 % compared with water flooding and CO2 flooding in the micromodel experiments; the CO2 foam with RC increased the injection pressure from 0.20 to 3.1 MPa in the core flooding experiments, suggesting the diversion of fluid from high permeable to low permeable zone. In terms of the EOR, the CO2 foam flooding with RC improved the oil recovery from the respective 29.7 % and 12.9 % to 92.3 % in contrast with water flooding and CO2 flooding in micro-flooding experiments and from 35.5 % to 56.4 % by core-flooding experiments; the underlying mechanisms are attributed to oil emulsification, rock wettability alteration and foam deformation. These insights provide new approaches to maintain foam stability, improve conformance control and EOR performances in heterogenous tight oil reservoirs under harsh conditions.

Induced carbonate dissolution: Impact of brine chemistry in CO2 foam

Foam CO2might be considered an efficient alternative to reduce gas mobility and produce favorable mobility ratios. It offers significant advantages, particularly in heterogeneous or fractured reservoirs due to its ability to block highly permeable layers or divert the injected fluid from fractures into the matrix. In the present work, a surfactant solution made of different ionic compositions was co-injected into outcrop Edwards Limestone to determine the impact of brine chemistry on carbonate dissolution upon CO2foam injection. The development in differential pressures (DP) during continuous co-injection of sc-CO2 and different surfactant solutions (NaCl, NFB, CB) shows that unwanted chemical reactions (dissolution/precipitation) compromise the rock integrity by more acid formation and wormholing. Rock-fluid-foam interactions indicate that the total heat in the rock-fluid-foam systems is 6.9 mJ NaClfoam, 19.3 mJ NFBfoam, and 37.8 mJ CBfoam systems. On the other hand, the total heat for the fluid-foam interactions is 11.5 mJ NaClfoam, 12.5 NFBfoam, and 20.4 mJ CBfoam. The demicellization of the foam formulations could have led to calcite dissolution. The synergy between ITC and core flooding experiments elucidates the impact of the brine chemistry on calcite dissolution during foam-assisted CO2sequestration at both microscopic and macroscopic scales.

A Pore-Level Study of Dense-Phase CO2 Foam Stability in the Presence of Oil

The ability of foam to reduce CO2 mobility in CO2 sequestration and CO2 enhanced oil recovery processes relies on maintaining foam stability in the reservoir. Foams can destabilize in the presence of oil due to mechanisms impacting individual lamellae. Few attempts have been made to measure the stability of CO2 foams in the presence of oil in a realistic pore network at reservoir pressure. Utilizing lab-on-a-chip technology, the pore-level stability of dense-phase CO2 foam in the presence of a miscible and an immiscible oil was investigated. A secondary objective was to determine the impact of increasing surfactant concentration and nanoparticles on foam stability.In the absence of oil, all surfactant-based foaming solutions generated fine-textured and strong foam that was less stable both when increasing surfactant concentrations and when adding nanoparticles. Ostwald ripening was the primary destabilization mechanism both in the absence of oil and in the presence of immiscible oil. Moreover, foam was less stable in the presence of miscible oil, compared to immiscible oil, where the primary destabilization mechanism was lamellae rupture. Overall, direct pore-scale observations of dense-phase CO2 foam in realistic pore network revealed foam destabilization mechanisms at high-pressure conditions.

The impact of chelating agent pH on the stability and viscosity of CO2 foam under harsh reservoir conditions

The injection of CO2 foam into the carbonate reservoir for enhanced oil recovery (EOR) has attracted special interest in the last decades; nevertheless, the understanding of the effect of liquid solution chemistry on foam stability at high temperatures and salinities is limited. Hence, this paper fully investigates the effect of chelating agents L-glutamic acid-N, N-diacetic acid (GLDA) pH, and hydrochloric acid (HCl) on the stability and viscosity of generated CO2 foam for heterogeneous carbonate formation under reservoir conditions. In this paper, Duomeen TTM and Armovis VES surfactants were utilized due to their capabilities to produce viscous CO2 foam under harsh conditions. The foamability, foam stability, and foam structure were studied at 100 °C and 1000 psi using a high-temperature and high-pressure (HPHT) foam analyzer. The measurement of CO2 foam viscosity was determined at 100 °C, 1000 psi, and 70 % foam quality using the HPHT foam rheometer. Rheology experiments and dynamic light scattering investigated the micelle’s size or aggregation behavior of surfactants. The obtained results showed that the Duomeen TTM generated unstable foam; however, foam stability and foamability improved with the decrease in GLDA pH. Armovis VES showed excellent CO2 foam performance, where the foam half-life time of Armovis VES systems was 240 min. The liquid drainage and bubble coarsening were delayed due to the formation of the viscoelastic liquid phase. The foamability of Armovis VES was improved as the GLDA pH decreased. Furthermore, the addition of HCl to Armovis VES solution presented the highest foamability. The outcomes of the HPHT foam analyzer and HPHT viscometer proved that as the pH of Armovis VES solution decreased, higher foamability was produced. The highest foam viscosity was obtained using the synergic effect of 0.5 wt% Duomeen TTM and 0.5 wt% Armovis VES (39 cp at 100/s). In comparison, 1 wt% Armovis VES presented the lowest foam viscosity (30 cp at 100/s). The outcomes of this research can provide insight into the effect of chemistry on CO2 foam and extend its application in oilfield development. This work broadens the design of novel CO2 foam formulation, leading to the improvement of sweep efficiency in CO2-EOR methods and enhance the gas trapping in carbon storage.

CO2 Geostorage and Enhanced Oil Recovery: Challenges in Controlling Foam/Emulsion Generation and Propagation.

CO2 injection in subterranean reservoirs for storage, oil recovery, or both is challenging because of its very high mobility. Using a CO2 foam or emulsion is a way to remedy this problem by increasing CO2's apparent viscosity. However, the generation of the foam and its propagation in porous media present several issues that have to be overcome for this process to be economically realistic in practice. For example, it may take time, i.e., a number of pore volumes to be injected, before the foam is created. It is the objective of this Article to investigate these issues thoroughly and to identify the mechanisms underlying them by looking at the effects of various parameters. It is found that surfactant adsorption on the surface of the rock is an important factor involved in the delay of foam formation, but this may not explain all of the results. The nature and morphology of the porous medium may be, in some cases, the dominant factors for foam generation and propagation. From an understanding of the origin of the encountered problem, relevant mitigation strategies are envisioned and evaluated. It is found, for example, that when appropriately formulated and injected with the proper process, foam or emulsion generation is strongly accelerated, which very significantly shortens the delay for achieving CO2 storage.

Research for Flow Behavior of Heavy Oil by CO2 Foam Viscosity Reducer-Assisted Steam (CFVAS) Flooding: Microscopic Displacement Experiment Study

Steam displacement is prone to cross-flow, small swept area, large oil–water ratio, large oil–water interfacial tension, and low oil displacement efficiency. Compared with steam flooding, foam flooding can effectively reduce the residual oil in the small throat of the main flow channel and the small hole in the near flow channel and increase the overall recovery factor. Therefore, researchers carried out CO2 and chemical agent-assisted steam displacement. However, at present, there is a lack of research on the occurrence mechanism and model of residual oil. Steam flooding often encounters challenges such as cross-flow, limited sweep area, and high oil–water ratio. Foam flooding offers a promising alternative by effectively reducing residual oil in narrow throats and the near flow channel, thereby enhancing overall recovery rates compared to steam flooding alone. Therefore, chemical agent-assisted steam flooding was applied to enhance heavy oil recovery. However, the occurrence mechanism and model of residual oil after chemical agent-assisted steam is not clear. To fill this gap, the CO2 foam viscosity reducer assisted steam (CFVAS) flooding technology has been adopted and carried out in several studies. First, the foam viscosity reducer was prepared and its foam properties (viscosity reduction effect, foam volume, and half-life) were tested. Subsequently, the CFVAS displacement experiments after steam flooding were carried out, and the flow behavior of the remaining oil in multiple regions (main flow channel, near flow channel, and far flow channel) was analyzed. Finally, the shape and number of remaining oil under different displacement stages were compared, and the occurrence mode of remaining oil under CFVAS displacement was determined. The results indicate the following: (1) During steam flooding, the amount of near flow channel residual oil decreased with injected pore volumes (PV), transforming into columnar structures in small perforations and film-like formations in far flow channels. (2) CFVAS flooding, including the foam stability mechanism, flow channel adjustment mechanism, and emulsification and dispersion mechanism, can improve overall recovery rates by 55.2% by driving the remaining oil in near flow channels. (3) During CFVAS flooding stage, crude oil mobility notably improved and flooding front expanded more evenly. Residual oil primarily existed as oil-in-water (O/W) emulsions with discontinuous columns. (4) In the CFVAS flooding stage, residual oil mainly formed O/W emulsions through emulsification and dispersion, with foam-filled large and medium pores, concentrating residual oil in thick and middle throats. This work can provide important references for injecting CO2 gas into reservoirs to enhance heavy oil recovery and promote carbon sequestration.

An Experimental Investigation of Surfactant-Stabilized CO2 Foam Flooding in Carbonate Cores in Reservoir Conditions

Carbon dioxide (CO2) injection for enhanced oil recovery (EOR) has attracted great attention due to its potential to increase ultimate recovery from mature oil reservoirs. Despite the reported efficiency of CO2 in enhancing oil recovery, the high mobility of CO2 in porous media is one of the major issues faced during CO2 EOR projects. Foam injection is a proven approach to overcome CO2 mobility problems such as early gas breakthrough and low sweep efficiency. In this experimental study, we investigated the foam performance of a commercial anionic surfactant, alpha olefin sulfonate (AOS), in carbonate core samples for gas mobility control and oil recovery. Bulk foam screening tests demonstrated that varying surfactant concentrations above a threshold value had an insignificant effect on foam volume and half-life. Moreover, foam stability and capacity decreased with increasing temperature, while variations in salinity over the tested range had a negligible influence on foam properties. The pressure drop across a brine-saturated core sample increased with an increasing concentration of surfactant in the injected brine during foam flooding experiments. Co-injection of CO2 and AOS solution at an optimum concentration and gas fractional flow enhanced oil recovery by 6–10% of the original oil in place (OOIP).

Effect of temperature on the friction behavior and mechanism of DLC film in CO2 foam fracturing environment

Diamond-like carbon (DLC) film is considered to be an attractive candidate material for reducing friction and wear in oil and gas equipment due to its low friction and high wear resistance. This study investigated the evolution of friction interfaces and tribochemical reaction at three different temperatures through reactive molecular dynamics simulations. The results reveal that the synergistic effect of atomic transfer layer and chemical passivation of DLC film leads to the decrease of friction force with increasing ambient temperature. The cumulative atomic transfer layer with increasing ambient temperature also contributes to the increase of wear amount, while the atomic lattice transition dominates friction temperatures. More importantly, the phenomenon of increased sp3 carbon atoms in DLC film is also temperature dependent.

Enhancing carbon dioxide foam flooding for Egyptian oil recovery: the role of Arabic gum nanocomposites in foam stability and interfacial properties

In response to the growing demand for environmentally sustainable solutions in the oil and gas sector. In this study, three nanocomposites, namely Arabic gum silica oxide (ASO), Arabic gum iron oxide (AIO), and Arabic gum iron silica oxide (AIS), were synthesized. Spectroscopic analyses confirmed the chemical composition of these nanomaterials, while visual inspection and dynamic light scattering (DLS) analysis were employed to evaluate their particle size distribution and stability. It was found that ASO demonstrated a significant 26.8% increase in oil recovery compared to pure Arabic gum (15.6%) when applied at a concentration of 5 wt.% during CO2 foam flooding. This enhancement can be attributed to the high foam volume (134.1 mL) and prolonged drainage half-life (3562.5 s) at 30 °C. Furthermore, ASO displayed favorable interfacial tension (32.21 mN/m) and a superior storage modulus (10−27 mN/m) compared to pure Arabic gum (10−28 mN/m and 46.13 mN/m, respectively), indicating enhanced elasticity and improved stability of bubble-lamellae, ultimately resulting in enhanced oil recovery. Conversely, AIO nanocomposite exhibited a negative impact on recovered oil (4.8%), attributed to its low stability (zeta potential: −3.6 mV). These findings underscore the potential of ASO as a promising foaming agent for efficient oil recovery processes.

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.

Nanoparticle-stabilized CO2 foam flooding for enhanced heavy oil recovery: A micro-optical analysis

Surfactant flooding is a well-known chemical approach for enhancing oil recovery. Surfactant flooding has the disadvantage that it cannot withstand the harsh reservoir conditions. Improvements in oil recovery and release are made possible by the use of nanoparticles and surfactants and CO2 co-injection because they generate stable foam, reduce the interfacial tension (IFT) between water and oil, cause emulsions to spontaneously form, change the wettability of porous media, and change the characteristics of flow. In the current work, the simultaneous injection of SiO2, Al2O3 nanoparticles, anionic surfactant SDS, and CO2 in various scenarios were evaluated to determine the microscopic and macroscopic efficacy of heavy oil recovery. IFT (interfacial tension) was reduced by 44% when the nanoparticles and SDS (2000 ppm) were added, compared to a reduction of roughly 57% with SDS only. SDS-stabilized CO2 foam flooding, however, is unstable due to the adsorption of SDS in the rock surfaces as well as in heavy oil. To assess foam's potential to shift CO2 from the high permeability zone (the thief zone) into the low permeability zone, directly visualizing micromodel flooding was successfully executed (upswept oil-rich zone). Based on typical reservoir permeability fluctuations, the permeability contrast (defined as the ratio of high permeability to low permeability) for the micromodel flooding was selected. However, the results of the experiment demonstrated that by utilizing SDS and nanoparticles, minimal IFT was reached. The addition of nanoparticles to surfactant solutions, however, greatly boosted oil recovery, according to the findings of flooding studies. The ultimate oil recovery was generally improved more by the anionic surfactant (SDS) solution including nanoparticles than by the anionic surfactant (SDS) alone.

Investigation of the Stability Mechanism of Stimulus-Responsive Wormlike Micelle-CO2 Foams in the Oil Phase.

Foam flooding is an important tool for reservoir development. This study aims to further investigate the interaction between stimulus-responsive wormlike micelle (WLM)-CO2 foams and crude oil. We performed micromorphology experiments as our major studies and used molecular dynamics simulations as an auxiliary tool for interfacial analysis. We utilized foam generation, liquid separation, and defoaming as the entry points of experimental research and energy as the quantitative assessment index to investigate the dynamic process of the action of different oil contents and oil phase types in a DOAPA@NaSal-H+ foam system. We also examined the role of NaSal in the generation and development of the foam system. Results indicated that the law of crude oil's effect on foam could be summarized as "low contents are beneficial and high contents are harmful." In addition, although the DOAPA@NaSal-H+ foam system has high compatibility for saturated and aromatic hydrocarbons, it is highly suitable for application in reservoir environments with relatively high asphaltene and resin contents. Through combined experimental and simulation approaches, we clarified the law governing the stability of the DOAPA@NaSal-H+ foam system in different oil-containing environments, identified the key role of NaSal, and provided a reference for the targeted application of the DOAPA@NaSal-H+ foam system in different oil reservoirs.

Preparation and properties of carbon dioxide foamed concrete using nanoparticles as foam stabilizer and pre–carbonated cement slurry

The stability of carbon dioxide (CO2) foam is critical for preparation and performance of CO2 foamed concrete (CFC). This study evaluated the effectiveness of nanoparticles for stabilizing CO2 foam and pre–carbonation of cement slurry for mitigating CO2 foam loss during CFC preparation, and conducted a comparative study of CO2 foam, pre-carbonized slurry and CFC, aiming at preparing CFC with excellent performance. The results demonstrated that the incorporation of nano–silica can significantly enhance the stability of CO2 foam, with an improved half–life and diameter distribution. The pre–carbonation process optimized consistency and alkalinity of cement slurry and increased the retention rate of CO2 foam after its introduction into cement slurry, thereby facilitating the production of low–density CFC. CFC exhibits high compressive strength and early internal temperature, and has a low water absorption. The presence of CO2 within pores and their subsequent formation of potential negative pressure via carbonation reaction contributed to a much lower thermal conductivity of CFC compared to air foamed concrete. Moreover, a thin layer of calcium carbonate was formed on the inner wall, which can densify the microstructure and modify the pores. Although the carbonation degree of CFC may be lower compared to that of conventional carbonation–cured foamed concrete, the internal and uniform carbonation within CFC greatly enhanced material strength. The non–destructive nuclear magnetic resonance results show that CFC has a more concentrated pore size distribution with fewer fine pores and a smaller pore throat radius.