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This study investigated the impact of cushion gas type and presence on the performance of underground hydrogen storage (UHS) in an offshore North Sea aquifer. Using numerical simulation, the relationship between cushion gas type and UHS performance was comprehensively evaluated, providing valuable insights for designing an efficient UHS project delivery. Results indicated that cushion gas type can significantly impact the process's recovery efficiency and hydrogen purity. CO 2 was found to have the highest storage capacity, while lighter gases like N 2 and CH 4 exhibited better recovery efficiency. Utilising CH 4 as a cushion gas can lead to a higher recovery efficiency of 80%. It was also determined that utilising either of these cushion gases was always more beneficial than hydrogen storage alone, leading to an incremental hydrogen recovery up to 7%. Additionally, hydrogen purity degraded as each cycle progressed, but improved over time. This study contributes to a better understanding of factors affecting UHS performance and can inform the selection of cushion gas type and optimal operational strategies. • Compositional numerical simulation of underground hydrogen storage in a North Sea aquifer utilising CMG-GEM. • Hydrogen recovery efficiency improves with the utilisation of cushion gas. • CO 2 exhibits highest storage capacity; N 2 and CH 4 improve recovery efficiency. • CH 4 as cushion gas leads to 80% recovery efficiency, minimizing lateral spreading and viscous fingering. • Cushion gas density dictates the efficiency of the underground hydrogen storage scheme. [ABSTRACT FROM AUTHOR]

Underground hydrogen storage (UHS) in aquifers, salt caverns and depleted hydrocarbon reservoirs allows for the storage of larger volumes of H 2 compared to surface storage in vessels. In this work, we investigate the impact of aquifer-related mechanisms and parameters on the performance of UHS in an associated North Sea aquifer using 3D numerical compositional simulations. Simulation results revealed that the aquifer's permeability heterogeneity has a significant impact on the H 2 recovery efficiency where a more homogenous rock would lead to improved H 2 productivity. The inclusion of relative permeability hysteresis resulted in a drop in the H 2 injectivity and recovery due to H 2 discontinuity inside the aquifer which leads to residual H 2 during the withdrawal periods. In contrast, the effects of hydrogen solubility and hydrogen diffusion were negligible when studied each in isolation from other factors. Hence, it is essential to properly account for hysteresis and heterogeneity when evaluating UHS in aquifers. • Numerical compositional simulation utilising CMG-GEM of underground hydrogen storage in a North Sea aquifer. • Hydrogen recovery efficiency improves as the storage cycles increase. • Heterogeneity and hysteresis are the most impactful mechanisms on underground hydrogen storage. • Hydrogen solubility and diffusion in water have a minimal impact on the storage process when studied separately. • Solubility and diffusion effects become more pronounced when studied in combination with each other and hysteresis. [ABSTRACT FROM AUTHOR]

In this work, geochemical modelling using PhreeqC was carried out to evaluate the effects of geochemical reactions on the performance of underground hydrogen storage (UHS). Equilibrium, exchange, and mineral reactions were considered in the model. Moreover, reaction kinetics were considered to evaluate the geochemical effect on underground hydrogen storage over an extended period of 30 years. The developed model was first validated against experimental data adopted from the published literature by comparing the modelling and literature values of H2 and CO2 solubility in water at varying conditions. Furthermore, the effects of pressure, temperature, salinity, and CO2% on the H2 and CO2 inventory and rock properties in a typical sandstone reservoir were evaluated over 30 years. Results show that H2 loss over 30 years is negligible (maximum 2%) through the studied range of conditions. The relative loss of CO2 is much more pronounced compared to H2 gas, with losses of up to 72%. Therefore, the role of CO2 as a cushion gas will be affected by the CO2 gas losses as time passes. Hence, remedial CO2 gas injections should be considered to maintain the reservoir pressure throughout the injection and withdrawal processes. Moreover, the relative volume of CO2 increases with the increase in temperature and decrease in pressure. Furthermore, the reservoir rock properties, porosity, and permeability, are affected by the underground hydrogen storage process and, more specifically, by the presence of CO2 gas. CO2 dissolves carbonate minerals inside the reservoir rock, causing an increase in the rock's porosity and permeability. Consequently, the rock's gas storage capacity and flow properties are enhanced. [ABSTRACT FROM AUTHOR]

In this work, the flooding processes of low salinity waterflooding and low salinity polymer flooding (LSWF and LSP) in sandstone reservoirs were mechanistically modelled at nano-and macro-scales. Triple-layer surface complexation models were utilised to simulate interactions at the oil-brine and sandstone-brine interfaces. The Derjaguin-Landau-Verwey-Overbeek (DLVO) theory was applied to describe the stability of interfacial films in crude oil-brine-sandstone rock systems. The novel application of the maximum energy barrier (MEB), calculated from the interaction potential of the DLVO theory, as an upscaling and interpolant parameter to adjust relative permeability curves as a function of reservoir properties is proposed in this work. Numerical simulations using the commercial simulator CMG-STARS were used in tandem with the surface complexation models and film analysis to evaluate the performance of LSWF and LSP in sandstone reservoirs. Results of the numerical simulations showed that the LSP gave significantly higher oil recovery compared to standard polymer flooding because of its utilisation of wettability alteration due to LSWF and the improved mobility control due to LSP. A comparison between studied injection processes i.e. low and high salinity waterflooding, and low and high salinity polymer flooding, revealed that oil recovery as a result of wettability alteration is significantly higher than that of mobility control. Further analysis indicated that temperature affects the wettability alteration favourably, and the polymer slug viscosity unfavourably. However, the temperature effect on the wettability was found to be more pronounced. The workflow presented in this study provides valuable guidelines in screening the appropriate sandstone reservoirs for LSWF and LSP applications using the numerical simulation techniques through the upscaling from nano-to-macro-to-field scale. [Display omitted] • Triple-layer surface complexation model (TLM) developed to describe crude oil-brine-sandstone interactions. • The novel application of maximum energy barrier (MEB) to upscale micro-scale interactions to macro-scale flow phenomena is proposed. • CMG-STARS simulation software was used in tandem with film stability analysis to perform numerical modelling. • Low salinity polymer flooding gave higher oil recovery than the separate low salinity waterflooding and polymer flooding processes. • Wettability alteration due to low salinity waterflooding was more pronounced than mobility control due to polymer flooding. [ABSTRACT FROM AUTHOR]

Low salinity waterflooding has been reported to yield incremental oil recovery from both field applications and laboratory experiments compared to regular waterflooding. Crude oil-brine-rock (COBR) interactions dictate wettability alteration during low salinity waterflooding in sandstones. In this work, triple-layer surface complexation modelling (TLM) is utilised to simulate the interactions at rock-brine and oil-brine interfaces, while accommodating the crucial role of sandstone mineralogy in surface chemistry. Derjaguin-Landau-Verwey-Overbeek (DLVO) theory is applied to characterise the COBR stability. Moreover, we propose the use of the maximum energy barrier (MEB) parameter, which is calculated from the DLVO theory's interaction potential, as an indicator of reservoir wettability. Correlating the MEB with the experimentally measured contact angles revealed an abrupt increase in contact angles as the MEB drops below the zero-value thereby leading to a less water-wet COBR system. Results analyses showed that the different clays affect the rock-brine zeta potential and wettability distinctly based on their surface site densities and specific surface areas. And the studied clays cause the zeta potential to become more negative in the order: smectite > montmorillonite > illite > chlorite > kaolinite. Subsequently, further investigation employing the developed TLM and MEB revealed that higher amounts of kaolinite will make the reservoir more oil-wet. Lastly, the sensitivity analysis performed on reservoir wettability indicated that the ionic composition is the most important factor to affect rock wettability followed by pH and temperature. Moreover, the presence of CaCl 2 salt in the formation water significantly supresses the areas of strong water wettability under varying reservoir conditions compared to NaCl salt. The work conducted in this study presents a novel approach to model the individual and combined effects of sandstone minerals, specifically, quartz, kaolinite, chlorite, illite, montmorillonite and smectite, on the overall sandstone zeta potential behaviour. Furthermore, a new method was proposed to characterise reservoir wettability as a function of the maximum energy barrier which allowed us to obtain valuable insights into the most affecting reservoir parameters on COBR wettability. These findings will have practical implications to efficiently design the low salinity waterflooding processes for sandstone reservoir applications. [Display omitted] • Developed a triple-layer surface complexation model (TLM) to describe sandstone-brine interactions. • Model validated using published experimental studies with accuracy between 78% and 90%. • The maximum energy barrier (MEB) is proposed to characterise reservoir wettability as a novel concept. • Investigated the most impactful parameters on sandstone reservoir wettability. • Sandstone reservoirs with higher content of kaolinite will lead the wettability to become less water wet. [ABSTRACT FROM AUTHOR]

Low salinity water flooding (LSWF) is a popular enhanced oil recovery technique. Among factors that affect the performance of LSWF, geochemical interaction at the oil-brine interface and the associated enterokinetic properties plays a prominent role. This work presents a triple-layer surface complexation model for predicting the zeta potential of the oil-brine interface. We improve upon previous modelling studies by incorporating the effects of (1) temperature variation, (2) basic (-NH) oil surface group interactions (3) adsorption of sodium ions on outer and inner Helmholtz planes and (4) the presence of sulphate ions in brine. Model validation against published experimental data shows model accuracy between 66% and 99%. The model displays higher accuracies at lower salinities (making it particularly suited for LSWF applications), intermediate pH and higher total acid number. In addition, a correlation between (-NH) site density and total acid/base numbers is proposed. A sensitivity study performed utilising the developed model showed that higher sulphate concentration in the brine and elevated temperature makes the zeta potential at the oil-brine interface more negative. In addition, the sensitivity study indicates that a higher concentration of basic polar oil compounds is less favourable as it may result in less water-wet conditions in the reservoir. [Display omitted] • Developed a triple-layer surface complexation model (TLM) to describe oil-brine interactions. • Addressed the limitations of the existing oil-brine triple-layer models. • Model Validation using data of 16 types of crude oil from 9 published experimental studies with accuracy between 66% and 99%. • A correlation between (-NH) site density and total acid/base numbers is proposed. • Results indicate that a higher concentration of basic polar oil compounds may result in less favourable wetting conditions. [ABSTRACT FROM AUTHOR]

Low salinity water flooding (LSWF) is a popular enhanced oil recovery technique. Among factors that affect the performance of LSWF, geochemical interaction at the oil-brine interface and the associated enterokinetic properties plays a prominent role. This work presents a triple-layer surface complexation model for predicting the zeta potential of the oil-brine interface. We improve upon previous modelling studies by incorporating the effects of (1) temperature variation, (2) basic (-NH) oil surface group interactions (3) adsorption of sodium ions on outer and inner Helmholtz planes and (4) the presence of sulphate ions in brine. Model validation against published experimental data shows model accuracy between 66% and 99%. The model displays higher accuracies at lower salinities (making it particularly suited for LSWF applications), intermediate pH and higher total acid number. In addition, a correlation between (-NH) site density and total acid/base numbers is proposed. A sensitivity study performed utilising the developed model showed that higher sulphate concentration in the brine and elevated temperature makes the zeta potential at the oil-brine interface more negative. In addition, the sensitivity study indicates that a higher concentration of basic polar oil compounds is less favourable as it may result in less water-wet conditions in the reservoir. [Display omitted] • Developed a triple-layer surface complexation model (TLM) to describe oil-brine interactions. • Addressed the limitations of the existing oil-brine triple-layer models. • Model Validation using data of 16 types of crude oil from 9 published experimental studies with accuracy between 66% and 99%. • A correlation between (-NH) site density and total acid/base numbers is proposed. • Results indicate that a higher concentration of basic polar oil compounds may result in less favourable wetting conditions. [ABSTRACT FROM AUTHOR]