Author Identifier

Mirhasan Hosseini

https://orcid.org/0000-0001-6400-0366

Date of Award

2023

Document Type

Thesis

Publisher

Edith Cowan University

Degree Name

Doctor of Philosophy

School

School of Engineering

First Supervisor

Stefan Iglauer

Second Supervisor

Alireza Keshavarz

Third Supervisor

Jalal Fahimpour

Abstract

The projected rise in demand for hydrogen (H2) production is a response to several factors, including greenhouse gas emissions caused by burning fossil fuels, depletion of fossil fuel reserves, and their uneven distribution around the earth. Thus, increased requirement for large-scale hydrogen storage solutions is anticipated to overcome imbalance between energy demand and supply. Deep underground formations such as salt caverns and porous reservoir rocks (e.g., depleted hydrocarbon reservoirs and deep saline aquifers) are necessary to achieve such volumes in practice. This process is known as underground hydrogen storage (UHS) which is technically very similar to underground natural gas storage. Although these two gas types have similar storage mechanisms, their behavior underground differs significantly, and this divergence could affect the efficiency, sustainability, safety, and commercial feasibility of deploying and operating gas storage systems. The interface and wetting characteristics of the various rock/H2/brine systems are significant physicochemical factors in controlling containment security and storage capacity. These factors demand a thorough assessment. Nevertheless, there exists a literature gap concerning these aspects under diverse geological conditions, encompassing variations in pressure, temperature, organic matter, and salinity.

This study presents experimental data on interfacial tension (IFT) values between H2 and brine as well as the wettability of different rock/H2/brine systems under reservoir conditions. The wettability measurements are taken by directly observing the advancing and receding contact angles of water using the pendant drop tilted-plate technique. The experiments are conducted at high pressures (up to 20 MPa), elevated temperatures (up to 353 K) and brine salinities (up to 4.95 mol.kg-1 ) to simulate subsurface conditions commonly encountered in such systems. For the investigation of wettability, various rocks were selected: calcite and Indiana limestone (which are representative of carbonate rocks); shales and evaporate (which are representative of caprocks), and basalt (which is representative of volcanic rocks). The effects of other rock surface properties such as surface roughness by atomic force microscopy (AFM) and organic matter concentration of shale by total organic content (TOC) analyzer on wettability were also investigated in this study. The study employed several other methods to characterize the composition of the rock and fluid samples, which included: 1) energy dispersive spectroscopy (EDS) to determine the elemental composition of the rock surface, 2) x-ray diffraction (XRD) to identify the mineral composition of the rock sample, and 3) inductively coupled plasma (ICP) to determine the elemental composition of the brine sample. The obtained IFT and contact angle data were utilized to theoretically calculate the IFT of various rock-hydrogen and rock-water systems by the combination of Young’s equation and Neumann’s equation of state. Additionally, the electrochemical mechanisms controlling the wetting behavior of basalt under various geological conditions were investigated via streaming zeta potential core flooding system.

The results of H2-brine interfacial tension indicate a linear decrease with increasing pressure and temperature, but a linear increase with increasing salinity over the entire range studied. The findings of the study reveal that in the majority of the rock/H2/brine systems analyzed, the water advancing and receding contact angles exhibited an increase (more H2-wet) with increasing pressure, salinity, and organic matter concentration but a decrease (more water-wet) with increasing temperature. Moreover, the samples with a high organic acid concentration showed a decrease in hydrophobicity following treatment with the nanofluid. The rock-hydrogen interfacial tension in shale, evaporite and basaltic rocks decreased with increasing pressure, temperature, and organic matter concentration. Also, the rock-water interfacial tension in these rocks decreased with increasing temperature but increased with increasing organic matter concentration. On the other hand, the calcite-hydrogen interfacial tension decreased with increasing pressure, salinity, and organic acid concentration, while it increased with increasing temperature. The calcite-water interfacial tension showed only minor variations with these parameters. Additionally, according to the findings, the zeta potential of basalt remained stable in response to pressure but showed an increase (less negative) trend as temperature and salinity increased. Conversely, the zeta potential of basalt exhibited a decrease (more negative) trend as the pH level increased.

This thesis offers valuable insights for evaluating the potential of different minerals composing the geological formations as H2 storage options. The outcomes of this study are especially useful for analyzing the capillary sealing efficiency of caprocks, which can help in identifying the factors that contribute to the leakage of H2. Furthermore, the information presented can be utilized as a valuable input in the development of H2/brine flow simulations, which have the potential to provide more accurate predictions and, therefore, reduce the uncertainty associated with H2 geostorage projects.

DOI

10.25958/swcn-8k45

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