By trapping CO2 and storing it in matured and depleted geological formations, atmospheric CO2 release can be reduced. Carbon capture and storage on a large scale can help to stabilize atmospheric greenhouse gas emissions. This can be achieved by using anthropogenic CO2 for enhanced oil recovery (EOR), which encourages advances in secure CO2 storage while enhancing the oil production process. This interaction is expected to hasten the development of CO2 storage technology and lower emissions from oil producing operations. Reducing CO2 mobility in the reservoir is crucial to achieving this goal as effectively as possible, and in situ foam generation offers a viable solution. It has been shown that implementing a blend of CO2 and foaming solution considerably reduces CO2 mobility and front propagation. Although there have been a few reviews of carbon capture, utilization, and storage (CCUS), none of these have concentrated on the role of foam EOR in achieving carbon neutrality. Therefore, in this brief review, methods for achieving carbon neutrality with foam EOR are comprehensively reviewed. In order to store CO2, the utilisation of atmospheric CO2 to generate foam is the main topic of this review. This approach can boost financial incentives for the energy sector, help to lower carbon emissions, and make it possible to produce oil from depleted reservoirs in a more sustainable way. Thus, identifying and examining the governing mechanisms that affect CO22 storage during foam flooding as well as reviewing the various techniques for estimating CO2 storage under actual reservoir circumstances are among the goals of this work.

A Comprehensive Review of the Role of CO2 Foam EOR in the Reduction of Carbon Footprint in the Petroleum Industry

The effects of CO2-water-rock interactions on the injectivity and safety of CO2 geological storage have drawn wide attention. The geochemical reaction mechanisms in carbonate formations after CO2 injection are still controversial. To better understand the transformation of injected CO2 in carbonates and the involved geochemical reactions, we first conducted autoclave experiments reproducing the in-situ conditions of the Lianglitage Formation, Yingshan Formation, and Qiulitage Formation at the Tazhong Uplift in the Tarim Basin. We then established a batch model using TOUGHREACT-ECO2H, validated with the experimental results, to simulate the long-term CO2-water-rock interactions. It was found that the initial mineral compositions and water chemistry have important effects on the CO2-water-rock interactions in carbonate formations. The experiment results show that the dissolution of calcite and dolomite dominates in the early reaction period. However, we still observed some secondary minerals, such as ankerite, montmorillonite, calcite, and dolomite. The CO2-water-rock reactions can be more dramatic when the contents of calcite and dolomite in carbonates are closer. Moreover, the long-term simulation results show that calcite, magnesite, and hematite are the main formed secondary minerals, whereas dolomite is the major dissolved mineral. This study is helpful for a better understanding of the CO2 mineral trapping mechanism in carbonate formations.

https://www.mdpi.com/2075-163X/12/5/635/pdf?version=1652782910

CO2-Water-Rock Interactions in Carbonate Formations at the Tazhong Uplift, Tarim Basin, China

Geologic carbon storage (GCS) is a rapidly evolving technology with the potential to reduce the environmental impact of fossil fuel usage. Saline aquifers, which comprise a sandstone matrix with brine contained in the pores, make up much of the pore space available for CO2 storage in the United States. When CO2 is injected in saline aquifers, however, capillary fingering occurs, and only a small percentage of the pore space is filled with CO2. This fingering effect is due to the low viscosity of CO2, which is roughly ten times less viscous than brine. To address this problem, we tested the ability of inexpensive, commercially available nonionic surfactants to be dissolved in injected CO2 and increase the apparent viscosity of CO2 by generating CO2-in-water foams in situ. We focused our study on nonionic tridecyl ethoxylate surfactants with the number of ethoxylate groups ranging from 11 to 18 (TDA-11, TDA-13, TDA-15, TDA-18). These surfactants exhibited sufficient CO2-solubility and were shown to reduce the CO2-brine interfacial tension (IFT), stabilize bulk CO2-in-brine foams, and reduce the mobility of CO2 during core floods of CO2 in brine-saturated Berea sandstone. The surfactants did not alter the wettability of the Berea sandstone. Modeling results showed that in a reservoir field injection scenario, the presence of TDA-11 (0.1 wt %) increased both the CO2 storage resource and storage efficiency by 17%. Simulations also showed that the lateral extension area of the plume was reduced by 23% and that CO2 saturation within the plume increased by 26%. 

CO2-Soluble Nonionic Surfactants for Enhanced CO2 Storage via In Situ Foam Generation

Carbonate reservoirs are made up of predominantly calcite and dolomite minerals and hold significant hydrocarbon reserves globally. However, the production from carbonate reservoirs is limited due to their wettability, which controls the production and fluid distribution. To develop efficient strategies for producing from these formations, it is necessary to understand the underlining mechanisms of carbonate rock wettability. We believe that understanding the native state of the rock mineral in the reservoir environment and how oilfield operations affect the wetting state of minerals is critical to demystifying the change in carbonate rock wettability. Thus, this study extends the understanding of the surface charge development of calcite minerals and provides useful insight into the mineral’s surface charge development. Zeta potential measurements and molecular dynamics (MD) simulations of calcite in different fluids of varying composition and salinity were investigated. We have considered both the mixed brine (seawater and reservoir water) and individual salt brine (i.e., NaCl, MgCl2, and CaCl2). The results show that the calcite mineral surface charge is controlled by the composition and salinity of the surrounding fluids. Indeed, we found that monovalent ions have dominant contributions to the total calcite surface charge. The adsorptions of Na+ and Cl– shape the stern layer structure in the first two calcite hydration monolayers. We found that the interplay between the calcite surface affinity to the brine ions and the hydration-free energies are the two critical parameters shaping the final mineral surface charge. We believe that our study provides essential atomic insights into the calcite–brine interfaces and how ions interact with the surface to control the surface charge, which are vital to the quest for wettability control. 

Calcite–Brine Interface and Its Implications in Oilfield Applications: Insights from Zeta Potential Experiments and Molecular Dynamics Simulations

Recently, the application of low salinity water (LSW), nanoparticles (NPs), and surfactants (collectively abbreviated as LNS) in carbonate formations for enhanced oil recovery (EOR) purposes has been under investigation, but relatively few studies have been performed for their implementation in fractured carbonate reservoirs (FCRs). The objective of this study is to apply the recently proposed method of alternatively injecting LNS in cycles into FCRs using silica and zirconia NPs. The cumulative oil recovered from the two coreflooding experiments performed at 3000 psi overburden pressure and 70 °C temperature is reported in this study in addition to spontaneous imbibition (SI) experiments. The experimental design is structured to depict the best industrial practice for the injected fluids in FCRs. Furthermore, this work investigates the effect of zirconia NPs on the interfacial tension (IFT) between the injected fluids and crude oil under the previously stated experimental conditions. The outcome of these experiments divulges that the alternating injection of LNS employing silica and zirconia NPs is effective and well suited for EOR applications in FCRs owing to a cumulative oil recovery of approximately 8 and 7% of the original oil in place (OOIP), respectively. This study validates the implementation of the recently proposed alternating injection of the LNS technique for FCRs and shows its performance utilizing newly acquired zirconia NPs, which is relevant for industrial application at a large scale. 

Experimental Study on Alternating Injection of Silica and Zirconia Nanoparticles with Low Salinity Water and Surfactant into Fractured Carbonate Reservoirs for Enhanced Oil Recovery

The impact of ionic association with the carbonate surface and its influence toward carbonate wettability remains unclear and is an important topic of interest in the current literature. In this work, a triple layer model (TLM) approach was used to capture the electrokinetic interactions at both calcite–brine and oil–brine interfaces. The developed TLM was assembled against measured ζ-potential values from the literature, successfully capturing the trends and closely matching the ζ-potential magnitudes. The developed TLM was compared to a diffused layer model (DLM) presented in previous works, with the DLM showing a better match to the ζ-potential values for seawater brine solutions. The ζ-potential values predicted from both surface complexation models (SCMs) were used to calculate the total interaction energy (or potential) based on the Derjaguin, Landau, Verwey, and Overbeek (DLVO) theory. It was observed that low Mg2+ and high SO42– concentrations in modified composition brine (MCB) made the calcite–brine interface more negative. However, at the oil–brine interface, low Mg2+ made the oil–brine interface more negative but high SO42– concentrations slightly shifted the oil–brine ζ-potential toward negative. At the crude oil–brine–rock (COBR) interfaces, low Mg2+ and high SO42– concentrations in the MCB were observed to generate a greater repulsive interaction energy, which could trigger carbonate wettability alteration toward water wetness. The absolute sum of the ζ-potential at both interfaces was observed to be correlated to the total interaction potential at a 0.25 nm separating distance. Thus, an increase in the absolute sum of the ζ-potentials would generate a greater repulsive interaction potential and trigger wettability alteration. Therefore, these SCMs can be applied to design modified composition brine capable of triggering a repulsive interaction energy to alter carbonate wettability toward water wetness.

https://kuscholarworks.ku.edu/bitstream/1808/32738/1/Tetteh_2022.pdf

Ionic Interactions at the Crude Oil–Brine–Rock Interfaces Using Different Surface Complexation Models and DLVO Theory: Application to Carbonate Wettability


 Utilizing foam techniques in carbon storage projects is of recent interest, yet whether the optimized bulk foam screening method could also identify the optimal foam formulation that improves the CO2 storage potential remains under-studied. This study demonstrates the feasibility of the bulk foam test as a screening stage to select a proper foaming agent for carbon storage by investigating the consistency of the results obtained from bulk foam properties measurements, dynamic foam performance evaluations in porous media, and the quantification of CO2 storage potential at the reservoir conditions. Different foaming agents were initially screened based on their abilities to generate ample and stable foam at 13.79 MPa and 90°C. The CO2 storage potential was studied based on the CO2 breakthrough deceleration and water displacement efficiency, while the dynamic performance of supercritical CO2-foams stabilized by these selected surfactants was then evaluated in Berea sandstone using the CO2/surfactant co-injection method. Among the tested surfactants in bulk CO2 foam experiments at high pressure and temperature conditions, a sultaine-based zwitterionic surfactant was identified to exhibit the highest foamability and foam stability. In flooding experiments, the selected surfactant was able to provide decent foam generation ability that leads to the best performance in improving the CO2 storage potential by two-fold magnitude, compared to the brine-saturated core case. Besides, an immediate foam generation was observed, providing high flow resistance for the injected CO2 and, therefore, resulting in controlled CO2 mobility and improved CO2 sweep efficiency. The result coherency from CO2 storage potential evaluations and foam performance assessments both in bulk and inside porous media shows the feasibility of the bulk foam screening method for the carbon storage studies. The initial identification of high-performing surfactants based on their bulk foaming properties can provide countable insights for CO2 storage potential improvement.

Feasibility of Bulk CO2-Foam Screening for Carbon Storage Evaluations at Reservoir Conditions

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Ionic Interactions at the Crude Oil–Brine–Rock Interfaces Using Different Surface Complexation Models and DLVO Theory: Application to Carbonate Wettability

Feasibility of Bulk CO2-Foam Screening for Carbon Storage Evaluations at Reservoir Conditions