CO2 In Deep Saline Formations Research Articles

Impact of mineral composition and distribution on the mechanical properties of porous media

Geological sequestration of CO2 in deep saline formations is a promising means of reducing atmospheric CO2 emissions. Once injected, CO2 dissolves into formation brine, lowering pH and creating conditions favorable for mineral dissolution. Cations released from dissolving minerals may create conditions favorable for secondary mineral precipitation, which can result in the long-term mineralogical trapping of injected CO2. These reactions may alter the natural rock mechanical properties, which can affect the safety and efficiency of geological sequestration. This work aims to investigate the impact of mineral composition and distribution on the mechanical properties of porous media. In this study, the mineralogy, mineral distribution, and mechanical properties of samples from Escambia County, AL, are evaluated. The mechanical properties of the rock samples are evaluated using the unconfined compression and indirect tensile tests in the combination with digital image correlation. The mineral composition and distribution are determined through the analysis of scanning electron microscopy backscattered electron and energy dispersive X-ray spectroscopy images of thin sections. These analyses showed that the mechanical properties vary with composition, which may have significant practical consequences for geological sequestration of CO2.

Simulations of CO2 storage in aquifer models with top surface morphology and transition zones

When investigating the storage of CO2 in deep saline formations, many studies assume a smooth, abrupt interface between the storage and the sealing formations. Typically, though, the surface is irregular, due to sedimentological and stratigraphic effects or structural deformation. In this study, the area where the CO2 migrates beneath the caprock is investigated. A set of numerical simulations were conducted to investigate the impacts of various factors on CO2 storage, such as top morphology, tilt, kv/kh ratio and the presence of a transition zone, where there is a gradational change from storage formation to caprock.In the models tested, the kv/kh ratio was most important during the injection period, but after injection ceased, the tilt was more important. The amplitude of the ridges, which were used to represent the top morphology, did not have a large effect but, as expected hindered or encouraged migration depending on whether they were perpendicular or parallel to the tilt. A transition zone can increase the security of storage by lessening the amount of CO2 accumulating underneath the caprock. Therefore it is important to characterise the interface in terms of the size of irregularities and also in terms of the existence of any transition zone. The latter has not been addressed in previous works. A simple formula was derived to predict the limiting tilt for trapping to occur in models with a sinusoidal interface with wavelength, λ, and amplitude, A. Although this is a simplified approach, it provides a means of assessing whether the topography of the top surface will give rise to significant trapping or not.

Effects of geochemical reactions on injectivity of CO2 in deep saline formations

ABSTRACTCO2 geological storage into deep saline aquifers is one of the most promising methods for reducing anthropogenic CO2 emissions into the atmosphere. During the CO2 geological storage, many factors may affect the final success of actual storage projects, including storability, injectivity, and seal security. In order to investigate the impact of the desiccation phenomenon on the physical and chemical behaviors around the injection well, a series of numerical simulations were performed. Simulation results demonstrated that the geochemical reactions play an important role in the CO2 injection stage, especially the dissolution of easily soluble minerals, such as carbonates and sulfate.

A comparison of volumetric and dynamic CO2 storage resource and efficiency in deep saline formations

A reliable carbon dioxide (CO2) storage resource estimation method is crucial if carbon capture and storage in deep saline formations (DSFs) is to gain widespread deployment for reducing anthropogenic CO2 emissions to the atmosphere. Most of the published methodologies are based on a volumetric calculation and do not consider the effect of site-specific dynamic factors (e.g., injection rate, pressure interference). Several studies suggest these dynamic components may play the dominant role in storing CO2 in DSFs. In this study, CO2 storage resource estimates and efficiencies for two deep saline systems were calculated using volumetric and dynamic methodologies.Comparison of the results indicates that dynamic CO2 storage efficiency is time-dependent. For short injection lengths (∼50 years), an open system has an efficiency similar to a closed system, and volumetric storage resource estimates are too high. For long injection time frames (∼2000 years), the dynamic storage resource of open systems approaches the volumetric potential. These results suggest that volumetric assessments are reliable provided it is understood that it may take hundreds of wells and/or injection for hundreds of years to reach a formation's effective CO2 storage resource potential. Additionally, operational factors such as water extraction can increase CO2 storage resource and efficiency.

A combined seismic and geoelectrical monitoring approach for CO2 storage using a synthetic field site

This paper presents an approach to assess the methods of 2D elastic seismic full waveform inversion (FWI) and electrical resistivity tomography (ERT) for monitoring storage of CO2 in deep saline formations. As at a real site the subsurface is not fully known, this approach uses a synthetic field site. Densities and saturations are obtained from a numerical simulation of the injection process and are introduced into geophysical forward models which simulate the geophysical data acquisition from the surface (FWI) and boreholes (ERT). These synthetic geophysical data are then evaluated with respect to changes in CO2 saturation and are compared to the fully known CO2 saturation of the numerical process model to verify the geophysical monitoring methods. Results show that both methods are capable of detecting a thin CO2 phase body in about 2,200 m depth for a synthetic site in the North German Basin. Inverted CO2 saturations are in good agreement, however, both methods cannot resolve the CO2 phase edges of less than 4 m saturated thickness. The maximum error of estimated CO2 saturation is 10 % for the FWI method and 15 % for the ERT method, if accurate baseline models are available. The FWI method sensitivity on the baseline model is tested by a sensitivity analysis demonstrating high sensitivity on bulk density, but low sensitivity on fluid densities and porosity. ERT results are considerably improved using structural information from the FWI as constraint.

Evaluation of two alternative carbon capture and storage technologies: A stochastic model

In this paper we evaluate two alternative CCS technologies at a coal-fired power plant from an investor's point of view. The first technology uses CO2 for enhanced oil recovery (EOR) paired with storage in deep saline formations (DSF) and the second merely stores CO2 in DSF. The paper updates and improves on an earlier publication by Tzimas et al. (2005). For projects of this type there are many sources of risk, three of which stand out: the price of electricity, the price of oil and the price of carbon allowances. In this paper we develop a general stochastic model that can be adapted to other projects such as enhanced gas recovery (EGR) or industrial plants that use CO2 for either EOR or EGR with CCS. The model is calibrated with UK data and applied to help understand the conditions that generate the incentives needed for early investments in these technologies. Additionally, we analyse the risks of these investments. Investments with EOR and secondary DSF storage can only be profitable (NPV > 0) when there is a high long-term equilibrium price for oil of more than $56.38/barrel. When the investment decision can be made at any time, i.e. there is an option value, then the trigger value for optimal investment is significantly higher.

Density-driven enhanced dissolution of injected CO2 during long-term CO2 geological storage

Geological storage of CO2 in deep saline formations is increasingly seen as a viable strategy to reduce the release of greenhouse gases into the atmosphere. However, possible leakage of injected CO2 from the storage formation through vertical pathways such as fractures, faults and abandoned wells is a huge challenge for CO2 geological storage projects. Thus, the density-driven fluid flow as a process that can accelerate the phase change of injected CO2 from supercritical phase into aqueous phase is receiving more and more attention. In this paper, we performed higher-resolution reactive transport simulations to investigate the possible density-driven fluid flow process under the ‘real’ condition of CO2 injection and storage. Simulation results indicated that during CO2 injection and geological storage in deep saline formations, the higher-density CO2-saturated aqueous phase within the lower CO2 gas plume migrates downward and moves horizontally along the bottom of the formation, and the higher-density fingers within the upper gas plume propagate downward. These density-driven fluid flow processes can significantly enhance the phase transition of injected CO2 from supercritical phase into aqueous phase, consequently enhancing the effective storage capacity and long-term storage security of injected CO2 in saline formations.

Guidelines for Reservoir Modeling of Geologic CO2 Storage

The process of identifying suitable sites for storage of CO2 in deep saline formations involves methodical and careful analysis of the technical and non-technical features of potential storage areas. This process is largely analogous to that used in the petroleum industry through which a project matures from an exploration project to a producing project. The goal is to ensure that CO2 can be successfully and securely stored over extended periods of time in a manner that is compliant with the best engineering and geological practices, applicable regulations, and the best interests of local and regional stakeholders. Dynamic reservoir modeling is a key component of the process at all stages, from initial site screening and selection, through development planning, project implementation and operation, to site closure and post-injection monitoring.This paper summarizes guidelines for dynamic reservoir modeling of CO2 storage in deep saline formations. The guidelines draw heavily upon existing petroleum industry best practices for reservoir modeling of conventional oil and gas developments, but also consider modeling issues raised by the CO2 storage research community and historical CO2 and acid gas injection experience. Topics discussed include:•Physical and chemical processes that need to be considered•Project design options to manage CO2 plume growth and promote safe, efficient, and reliable storage in different geologic settings•Design of models to address specific issues such as injectivity, storage capacity and security, and the long-term fate of the CO2Although reservoir modeling has applications across all phases of a CO2 storage project, this paper focuses on modeling activities specific to site selection and development planning that are aimed at identifying suitable candidate sites having sufficient storage resource, confining formations, and the capability to retain the injected CO2 over hundreds of years. Modeling results are also used to assist several additional activities including: calculation of the Area of Review for monitoring of CO2 plume migration and pressure buildup, determination of the most advantageous injection intervals and operation parameters to maximize injectivity and storage efficiency, assessment of potential leakage pathways, mitigation options, and risk evaluation.

Migration and Storage Mechanisms of CO<sub>2</sub> with Different Injection Rates

Geological sequestration of CO2 in deep saline formations has been considered as an effective way to mitigate the greenhouse effect. With different rates of injection to a storage formation, the migration and storage mechanisms of CO2 are different. In this paper, we simulated the migration of CO2 based on a generic geological reservoir under simplified conditions. The results show that higher injection rate will lead to higher migration velocity and farther distance from the injection well, while it has no influence on dissolution amount when the total amounts of injected CO2 are equal.

Modeling of fate and transport of coinjection of H2S with CO2in deep saline formations

[1] The geological storage of CO2 in deep saline formations is increasingly seen as a viable strategy to reduce the release of greenhouse gases into the atmosphere. However, costs of capture and compression of CO2 from industrial waste streams containing small quantities of sulfur and nitrogen compounds such as SO2, H2S, and N2 are very expensive. Therefore, studies on the coinjection of CO2 containing other acid gases from industrial emissions are very important. In this paper, numerical simulations were performed to study the coinjection of H2S with CO2 in sandstone and carbonate formations. Results indicate that the preferential dissolution of H2S gas (compared with CO2 gas) into formation water results in the delayed breakthrough of H2S gas. Coinjection of H2S results in the precipitation of pyrite through interactions between the dissolved H2S and Fe2+ from the dissolution of Fe-bearing minerals. Additional injection of H2S reduces the capabilities for solubility and mineral trappings of CO2 compared to the CO2-only case. In comparison to the sandstone (siliciclastic) formation, the carbonate formation is less favorable to the mineral sequestration of CO2. In sandstone and carbonate formations, the presence of Fe-bearing siliciclastic and/or carbonate is more favorable to the H2S mineral trapping.