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A magnetic resonance imaging study was conducted to explore the kinetics and spatial characteristics of the thermally induced methane hydrate formation in both synthetic and natural sediment samples. Low-resolution images were taken from the sediment samples during the hydrate formation and dissociation stages of three consecutive thermal cycles and the induction time, hydrate formation rate and duration, spatial distribution of water, and saturation of all co-existing phases were determined in order to understand the effect of the first cycle of the formation/dissociation on the subsequent cycles. The results demonstrate that the induction and hydrate formation times of the second and third thermal cycles decrease due to the memory effect, enhanced dissolution of methane in the aqueous phase and the redistribution of water associated with the first cycle of the hydrate formation and dissociation. Moreover, the hydrate formation proceeds with a fairly smooth and fast trend in the subsequent cycles primarily due to the multiple nucleation events, in contrast with the traditionally believed “fits and starts” manner which was observed for the first cycle. The thermal cycles for the natural sediment sample were compared with those for the synthetic sediment sample in terms of the induction time, hydrate formation behaviour and duration, and spatial distribution to understand how the sediment particle type and size distribution could influence the cyclic hydrate formation/dissociation. High-resolution images were also taken from the samples and used to infer the spatial distribution of methane hydrates, gas and water in pore space after completion of the hydrate formation stage of each thermal cycle, by applying an innovative image analysis approach.

The present study investigates the evolution of gas hydrate-bearing permafrost sediments against the environmental temperature change. The elastic wave velocities and effective thermal conductivity (ETC) of simulated gas hydrate-bearing sediment samples were measured at a typical range of temperature in permafrost and wide range of hydrate saturation. The experimental results reveal the influence of several complex and interdependent pore-scale factors on the elastic wave velocities and ETC. It was observed that the geophysical and geothermal properties of the system are essentially governed by the thermal state, saturation and more significantly, pore-scale distribution of the co-existing phases. In particular, unfrozen water content substantially controls the heat transfer at sub-zero temperatures close to the freezing point. A conceptual pore-scale model was also proposed to describe the pore-scale distribution of each phase in a typical gas hydrate-bearing permafrost sediment. This study underpins necessity of distinguishing ice from gas hydrates in frozen sediments, and its outcome is essential to be considered not only for development of large-scale permafrost monitoring systems, bus also accurate quantification of natural gas hydrate as a potential sustainable energy resource in cold regions.

Quantification of hydrates in permafrost sediments using conventional seismic techniques has always been a major challenge in the study of the climate-driven evolution of gas hydrate-bearing permafrost sediments due to almost identical acoustic properties of hydrates and ice. In this article, a coupled geophysical–geothermal scheme is developed, for the first time, to predict hydrate saturation in gas hydrate-bearing permafrost sediments by utilising their geophysical and geothermal responses. The scheme includes a geophysical part which interprets the measured elastic wave velocities using a rock-physics model, coupled with a geothermal part, interpreting the measured effective thermal conductivity (ETC) using a new pore-scale model. By conducting a series of sensitivity analyses, it is shown that the ETC model is able to incorporate the effect of the hydrate pore-scale habit and hydrate/ice-forced heave as well as the effect of unfrozen water saturation under frozen conditions. Given that the geophysical and geothermal responses depend on the overburden pressure, the elastic wave velocities and ETC of methane hydrate-bearing permafrost sediment samples were measured at different effective overburden pressures and the results were provided. These experimental data together with the results of our recent study on the geophysical and geothermal responses of gas hydrate-bearing permafrost sediment samples at different hydrate saturations are used to validate the performance of the coupled scheme. By comparing the predicted saturations with those obtained experimentally, it is shown that the coupled scheme is able to quantify the saturation of the co-existing phases with an acceptable accuracy in a wide range of hydrate saturations and at different overburden pressures.

In alignment with the Paris Agreement, more than 120 countries have now committed to reaching net zero by mid-century. Among the future energy storage technologies required for limiting global warming to well below 2 °C, geological storage of hydrogen is considered as a strong candidate to support increased renewable electrification. It is therefore crucial to understand the impact of injected hydrogen on geochemical equilibrium in these geological storage settings. Here, we investigate the potential for hydrogen reactions with different pure minerals using our custom high pressure/temperature batch reactors. Minerals examined include Gypsum, Calcite, Dolomite, and two types of Pyrite. We conducted the experiments at high pressure and temperature conditions with simulated reservoir brine, representing real geological conditions. Moreover, we conducted control experiments with inert nitrogen to ensure confidence that any identified geochemical reactions are induced by hydrogen, rather than elevated, temperature, pressure or brine chemistry. Our results suggest that abiotic geochemical reactions are not likely to result in hydrogen loss within the time scales of geological hydrogen storage.

Zero carbon energy generation from renewable sources can reduce climate change by mitigating carbon emissions. A major challenge of renewable energy generation is the imbalance between supply and demand. To overcome the energy imbalances, subsurface storage of hydrogen in porous mediais suggested as a large-scale and economic solution, yet its mechanisms are not fully understood. Important unknowns are the effect of the high migration potential of the small and mobile hydrogen molecule and the volume of recoverable hydrogen.We conducted non-steady state, cyclic hydrogen and brine injection experiments at 2-7 MPa and flow rates of 2-80 µl min-1 using water-wet Clashach sandstone cylinders of 4.7 mm diameter and 53-57 mm length (Clashach composition: ~96 wt.% quartz, 2% K-feldspar, 1% calcite, 1% ankerite). Two sets of experiments were performed using our new transparent flow-cell designed for x-ray computed microtomography: 1) Experiments using a laboratory x-ray source (University of Edinburgh) imaged the flow, displacement and capillary trapping of hydrogen by brine as a function of saturation after primary drainage and secondary imbibition. 2) Experiments using synchrotron radiation (Diamond Light Source, I12-JEEP tomography beamline) captured time-resolved hydrogen and brine flow and displacement processes. Pressure and mass flow measurements across the experimental apparatus complemented the microtomography volumes in both sets of experiments.Results from a water-wet rock show that hydrogen behaves as a non-wetting phase and sits in the centre of the pore bodies, while residual brine sits in corners and pore throats. Hydrogen saturation in the pore volume is independent of the injection pressure and increases with increasing hydrogen/brine injection ratio up to ~50% saturation at 100 % hydrogen. Capillary trapping of hydrogen during brine imbibition occurs via snap off and is greatest at higher brine injection pressures, with 10 %, 12% and 21% hydrogen trapped at 2, 5 and 7 MPa, respectively. Higher brine flow rates reduce capillary trapping and increase hydrogen recovery at any given injection pressure. Based on these results, future hydrogen storage operations should inject 100% hydrogen and manage the reservoir pressure to avoid high pressures and minimize capillary trapping of hydrogen during brine reinjection.Ongoing analysis of time-resolved experimental data will provide further insight into the critical pore-scale processes that ultimately influence the potential for geological hydrogen storage and recovery.

For fourteen days in November the world’s attention turned to the rise in atmospheric GHG levels, on this occasion with a special focus on methane (Nature 25 August 2021). Methane had previously been the subject of a study on gas hydrate formation and, while noting the relevance of this property to climate change modelling, the authors in that case wrote: `Curiously, gas hydrates seem to defy intuition about hydrophobic compounds, as the concentration of a nonpolar gas in the solid hydrate lattice is more than two orders of magnitude higher than the solubility of such a gas in liquid water’ (Walsh et al 2008 `Microsecond Simulations of Spontaneous Methane Hydrate Nucleation and Growth' ). The term `non-polar’ applies to the gases of Earth’s atmosphere - so does the same concentration paradox apply to the inclusion of each of these species in atmospheric ice? For CO2, curves published by the University of Lille quantify hydrate formation across a range of partial pressures, and are projected to a zero pressure origin, thereby embracing the partial pressure of the gas in Earth atmosphere (Chazallon and Pirim (2018) `Selectivity and CO2 capture efficiency in CO2-N2 clathrate hydrates investigated by in-situ Raman spectroscopy', Figs 4A and 4B). Moreover, in the presence of ice phase at -12°C our own results have shown that, from a CO2+N2 mixture, more than 90% of CO2 goes into the ice/hydrate phase, which is three times higher that at 10°C (Hassanpouryouzband et al 2019 `Geological CO2 capture and storage with flue gas hydrate formation in frozen and unfrozen sediments').We simulate hydrate formation in the Earth's atmosphere using laboratory apparatus designed to quantify the depletion of GHGs (including water vapour) from a chilled airstream at atmospheric pressure across a range of temperatures, followed by analysis of the condensate.

Zero carbon energy generation from renewable sources can reduce climate change by mitigating carbon emissions. A major challenge of renewable energy generation is the imbalance between supply and demand. To overcome the energy imbalances, subsurface storage of hydrogen in porous mediais suggested as a large-scale and economic solution, yet its mechanisms are not fully understood. Important unknowns are the effect of the high migration potential of the small and mobile hydrogen molecule and the volume of recoverable hydrogen.We conducted non-steady state, cyclic hydrogen and brine injection experiments at 2-7 MPa and flow rates of 2-80 µl min-1 using water-wet Clashach sandstone cylinders of 4.7 mm diameter and 53-57 mm length (Clashach composition: ~96 wt.% quartz, 2% K-feldspar, 1% calcite, 1% ankerite). Two sets of experiments were performed using our new transparent flow-cell designed for x-ray computed microtomography: 1) Experiments using a laboratory x-ray source (University of Edinburgh) imaged the flow, displacement and capillary trapping of hydrogen by brine as a function of saturation after primary drainage and secondary imbibition. 2) Experiments using synchrotron radiation (Diamond Light Source, I12-JEEP tomography beamline) captured time-resolved hydrogen and brine flow and displacement processes. Pressure and mass flow measurements across the experimental apparatus complemented the microtomography volumes in both sets of experiments.Results from a water-wet rock show that hydrogen behaves as a non-wetting phase and sits in the centre of the pore bodies, while residual brine sits in corners and pore throats. Hydrogen saturation in the pore volume is independent of the injection pressure and increases with increasing hydrogen/brine injection ratio up to ~50% saturation at 100 % hydrogen. Capillary trapping of hydrogen during brine imbibition occurs via snap off and is greatest at higher brine injection pressures, with 10 %, 12% and 21% hydrogen trapped at 2, 5 and 7 MPa, respectively. Higher brine flow rates reduce capillary trapping and increase hydrogen recovery at any given injection pressure. Based on these results, future hydrogen storage operations should inject 100% hydrogen and manage the reservoir pressure to avoid high pressures and minimize capillary trapping of hydrogen during brine reinjection.Ongoing analysis of time-resolved experimental data will provide further insight into the critical pore-scale processes that ultimately influence the potential for geological hydrogen storage and recovery.

Geological hydrogen storage in depleted gas fields represents a new technology to mitigate climate change. It comes with several research gaps, around hydrogen recovery, including the flow behavior of hydrogen gas in porous media. Here, we provide the first-published comprehensive experimental study of unsteady state drainage relative permeability curves with H2-Brine, on two different types of sandstones and a carbonate rock. We investigate the effect of pressure, brine salinity, and rock type on hydrogen flow behavior and compare it to that of CH4 and N2 at high-pressure and high-temperature conditions representative of potential geological storage sites. Finally, we use a history matching method for modeling relative permeability curves using the measured data within the experiments. Our results suggest that nitrogen can be used as a proxy gas for hydrogen to carry out multiphase fluid flow experiments, to provide the fundamental constitutive relationships necessary for large-scale simulations of geological hydrogen storage.

Subsurface storage of hydrogen, e.g. in depleted oil and gas fields (DOGF), is suggested as a means to overcome imbalances between supply and demand in the renewable energy sector. However, hydrogen is an electron donor for subsurface microbial processes, which may have important implications for hydrogen recovery, gas injectivity and corrosion. Here, we review the controls on the three major hydrogen consuming processes in the subsurface, methanogenesis, homoacetogenesis, and sulfate reduction, as a basis to estimate the risk for microbial growth in geological hydrogen storage. Evaluating our data on 42 DOGF showed that five of the fields may be considered sterile with respect to hydrogen-consuming microorganisms due to temperatures >122 °C. Only six DOGF can sustain all of the hydrogen consuming processes, due to either temperature, salinity or pressure constraints in the remaining fields. We calculated a potential microbial growth in the order of 1–17*107 cells ml−1 for DOGF with favorable conditions for microbial growth, reached after 0.1–19 days for growing cells and 0.2–6.6 years for resting cells. The associated hydrogen consumption is negligible to small (

Large hydrate reservoirs in the Arctic regions could provide great potentials for recovery of methane and geological storage of CO2. In this study, injection of flue gas into permafrost gas hydrates reservoirs has been studied in order to evaluate its use in energy recovery and CO2 sequestration based on the premise that it could significantly lower costs relative to other technologies available today. We have carried out a series of real-time scale experiments under realistic conditions at temperatures between 261.2 and 284.2 K and at optimum pressures defined in our previous work, in order to characterize the kinetics of the process and evaluate efficiency. Results show that the kinetics of methane release from methane hydrate and CO2 extracted from flue gas strongly depend on hydrate reservoir temperatures. The experiment at 261.2 K yielded a capture of 81.9% CO2 present in the injected flue gas, and an increase in the CH4 concentration in the gas phase up to 60.7 mol%, 93.3 mol%, and 98.2 mol% at optimum pressures, after depressurizing the system to dissociate CH4 hydrate and after depressurizing the system to CO2 hydrate dissociation point, respectively. This is significantly better than the maximum efficiency reported in the literature for both CO2 sequestration and methane recovery using flue gas injection, demonstrating the economic feasibility of direct injection flue gas into hydrate reservoirs in permafrost for methane recovery and geological capture and storage of CO2. Finally, the thermal stability of stored CO2 was investigated by heating the system and it is concluded that presence of N2 in the injection gas provides another safety factor for the stored CO2 in case of temperature change.

In this paper, characteristics of gas permeation through gas hydrate-bearing sediments were explored under varying differential pressure for three types of sedimentary core samples, including 100 wt % silica sand, 95 wt % silica sand +5 wt % montmorillonite clay, and consolidated sandstone using a standard core-holder. Results of the experiments indicate that capillary breakthrough, hydrate-forced heave or agglomeration and also Klinkenberg effect play important roles in controlling the gas permeation through different porous sediments, depending on the sediment type and properties such as grain/pore size distribution and degree of consolidation. It was observed that due to the presence of large pores in unconsolidated silica sand core samples, the gas flow is dominated at both hydrate-free and hydrate-bearing cases by the capillary breakthrough mechanism rather than the gas slippage which resulted in direct relationship between the gas permeability and the differential pressure. This mechanism was also observed to be dominant while measuring the gas permeability for the hydrate-free sandstone core sample. For the unconsolidated sand-clay core samples, higher saturation of methane hydrate led to relatively higher gas permeability due to hydrate-forced heave phenomenon which pushed the sediment grains apart from each other or hydrate agglomeration that formed inter-grain pores. Klinkenberg effect became significant for the hydrate-free sand-clay and hydrate-bearing sandstone core samples; however, it was not observed to be dominant in the hydrate-bearing sand-clay core samples due to the hydrate-forced heave and agglomeration until the inlet pressure was sufficiently high.

The climate system is changing globally, and there is substantial evidence that subsea permafrost and gas hydrate reservoirs are melting in high-latitude regions of the Earth, resulting in large vo...

To enable a fast transition of the global energy sector towards operation with 100% renewable and clean energy technology, the geological storage of hydrogen in depleted gas fields or salt caverns has been considered as a strong candidate for the future energy storage required for limiting global warming to well below 2 °C, as agreed under the Paris Agreement. As such, understanding the impact of injected hydrogen on the geochemical equilibrium in these storage reservoirs is critical. Here, using our bespoke high pressure/temperature batch reaction vessels we investigate the potential effects of hydrogen injection into 3 different sandstones reservoirs. These experiments were conducted at reservoir temperature and at different injection pressures from 1 to 20 MPa with salinities from 0 to 10 weight% over different time periods from 1 to 8 weeks. Our experiments reveal that there is no hydrogen-associated geochemical reaction for the selected sandstones. Although changing reservoir pressure slightly affected the mineral dissolution equilibria at ppm level for hydrogen injection scenarios, the fluctuations of mineral dissolution in water associated with pressure change have a negligible influence on the efficiency of geological hydrogen storage. Therefore, based on the analysis of water chemistry before and after the mentioned experiments, we demonstrate that from geochemical point of view geological storage of hydrogen in these sandstone reservoirs is safe and we don’t expect any hydrogen loss due to geochemical reactions.

Zero carbon energy generation from renewable sources can reduce climate change by mitigating carbon emissions. A major challenge of renewable energy generation is the imbalance between supply and demand. Subsurface hydrogen storage in porous media is suggested as a large-scale and economic means to overcome these energy imbalances. However, hydrogen is an electron donor for many subsurface microbial processes which may have important implications for hydrogen recovery, gas injectivity and corrosion.We reviewed the state-of-the-art literature on the controls on the three major hydrogen-consuming processes in the subsurface: methanogenesis, homoacetogenesis, and sulphate reduction, as a basis to develop a hydrogen storage site selection tool. Sites with low temperature (Testing our tool on 42 depleted gas and oil fields of the British and Norwegian North Sea and the Irish Sea showed that seven of the fields may be considered sterile with respect to hydrogen-consuming microorganisms due to either temperatures >122 °C or salinities >5 M NaCl. Only three fields can sustain all of the major hydrogen-consuming processes, due to either temperature, salinity or pressure constraints in the remaining fields. We calculated a potential microbial growth in the order of 1-17*107 cells ml-1 for these fields. The associated hydrogen consumption is negligible to small (

Expectations for energy storage are high but large-scale underground hydrogen storage in porous media (UHSP) remains largely untested. This article identifies and discusses the scientific challenges of hydrogen storage in porous media for safe and efficient large-scale energy storage to enable a global hydrogen economy. To facilitate hydrogen supply on the scales required for a zero-carbon future, it must be stored in porous geological formations, such as saline aquifers and depleted hydrocarbon reservoirs. Large-scale UHSP offers the much-needed capacity to balance inter-seasonal discrepancies between demand and supply, decouple energy generation from demand and decarbonise heating and transport, supporting decarbonisation of the entire energy system. Despite the vast opportunity provided by UHSP, the maturity is considered low and as such UHSP is associated with several uncertainties and challenges. Here, the safety and economic impacts triggered by poorly understood key processes are identified, such as the formation of corrosive hydrogen sulfide gas, hydrogen loss due to the activity of microbes or permeability changes due to geochemical interactions impacting on the predictability of hydrogen flow through porous media. The wide range of scientific challenges facing UHSP are outlined to improve procedures and workflows for the hydrogen storage cycle, from site selection to storage site operation. Multidisciplinary research, including reservoir engineering, chemistry, geology and microbiology, more complex than required for CH4 or CO2 storage is required in order to implement the safe, efficient and much needed large-scale commercial deployment of UHSP.

Expectations for energy storage are high but large-scale underground hydrogen storage in porous media (UHSP) remains largely untested. This article identifies and discusses the scientific challenges of hydrogen storage in porous media for safe and efficient large-scale energy storage to enable a global hydrogen economy. To facilitate hydrogen supply on the scales required for a zero-carbon future, it must be stored in porous geological formations, such as saline aquifers and depleted hydrocarbon reservoirs. Large-scale UHSP offers the much-needed capacity to balance inter-seasonal discrepancies between demand and supply, decouple energy generation from demand and decarbonise heating and transport, supporting decarbonisation of the entire energy system. Despite the vast opportunity provided by UHSP, the maturity is considered low and as such UHSP is associated with several uncertainties and challenges. Here, the safety and economic impacts triggered by poorly understood key processes are identified, such as the formation of corrosive hydrogen sulfide gas, hydrogen loss due to the activity of microbes or permeability changes due to geochemical interactions impacting on the predictability of hydrogen flow through porous media. The wide range of scientific challenges facing UHSP are outlined to improve procedures and workflows for the hydrogen storage cycle, from site selection to storage site operation. Multidisciplinary research, including reservoir engineering, chemistry, geology and microbiology, more complex than required for CH4 or CO2 storage is required in order to implement the safe, efficient and much needed large-scale commercial deployment of UHSP., This work was stimulated by the GEO*8 Workshop on “Hydrogen Storage in Porous Media”, November 2019 at the GFZ in Potsdam (Germany). NH, AH, ET, KE, MW and SH are funded by the Engineering and Physical Sciences Research Council (EPSRC) funded research project “HyStorPor” (grant number EP/S027815/1). JA is funded by the Spanish MICINN (Juan de la Cierva fellowship-IJC2018-036074-I). JM is co-funded by EU INTERREG V project RES-TMO (Ref: 4726 / 6.3). COH acknowledges funding by the Federal Ministry of Education and Research (BMBF, Germany) in the context of project H2_ReacT (03G0870C).

Summary The surface stability and resulting transmission of severe acute respiratory syndrome coronavirus 2 (SARS-CoV-2), specifically in indoor environments, have been identified as a potential pandemic challenge requiring investigation. This novel virus can be found on various surfaces in contaminated sites such as clinical places; however, the behavior and molecular interactions of the virus with respect to the surfaces are poorly understood. Regarding this, the virus adsorption onto solid surfaces can play a critical role in transmission and survival in various environments. In this article, we first give an overview of existing knowledge concerning viral spread, molecular structure of SARS-CoV-2, and the virus surface stability is presented. Then, we highlight potential drivers of the SARS-CoV-2 surface adsorption and stability in various environmental conditions. This theoretical analysis shows that different surface and environmental conditions including temperature, humidity, and pH are crucial considerations in building fundamental understanding of the virus transmission and thereby improving safety practices., Graphical Abstract, The Bigger Picture Challenges and opportunities•The novel SARS-CoV-2 can be recognized on various surfaces in a contaminated site, and its stability in different environmental conditions has been reported.•The literature suffers from the lack of fundamental understanding of molecular drivers of the virus-surface interactions, and the chemistry that occurs on the solid surfaces and its effects on the virus adsorption and stability is still in its nascent stages because of the complexity of the phenomena.•The roles of fluids pH values, surface chemistry, relative humidity, and temperature in the virus adsorption and desorption phenomena and persistence of SARS-CoV-2 on surfaces should be explored, and experimental scientists need to unravel the molecular drivers implicated in this new coronavirus transmission from the surfaces in different environmental conditions., The main drivers of the SARS-CoV-2 adsorption onto the solid surfaces include surface active moieties of the viral proteins, hydrophilic/hydrophobic characteristics of the surface, pH of the bulk fluid, relative humidity, and temperature of the environment. The highlighted findings shed light onto the potential molecular interactions between the virus and solid surfaces, which leads to further virus adsorption, viability, and transmission processes, and can help the scientific community take necessary measures to tackle associated challenges.

Gas hydrates have received considerable attention due to their important role in flow assurance for the oil and gas industry, their extensive natural occurrence on Earth and extraterrestrial planets, and their significant applications in sustainable technologies including but not limited to gas and energy storage, gas separation, and water desalination. Given not only their inherent structural flexibility depending on the type of guest gas molecules and formation conditions, but also the synthetic effects of a wide range of chemical additives on their properties, these variabilities could be exploited to optimise the role of gas hydrates. This includes increasing their industrial applications, understanding and utilising their role in Nature, identifying potential methods for safely extracting natural gases stored in naturally occurring hydrates within the Earth, and for developing green technologies. This review summarizes the different properties of gas hydrates as well as their formation and dissociation kinetics and then reviews the fast-growing literature reporting their role and applications in the aforementioned fields, mainly concentrating on advances during the last decade. Challenges, limitations, and future perspectives of each field are briefly discussed. The overall objective of this review is to provide readers with an extensive overview of gas hydrates that we hope will stimulate further work on this riveting field.

To meet global commitments to reach net-zero carbon emissions by 2050, the energy mix must reduce emissions from fossil fuels and transition to low carbon energy sources. Hydrogen can support this transition by replacing natural gas for heat and power generation, decarbonising transport, and facilitating increased renewable energy by acting as an energy store to balance supply and demand. For the deployment at scale of green hydrogen (produced from renewables) and blue hydrogen (produced from steam reformation of methane) storage at different scales will be required, depending on the supply and demand scenarios. Production of blue hydrogen generates CO2 as a by-product and requires carbon capture and storage (CCS) for carbon emission mitigation. Near-future blue hydrogen production projects, such as the Acorn project located in Scotland, could require hydrogen storage alongside large-scale CO2 storage. Green hydrogen storage projects, such as renewable energy storage in rural areas e.g. Orkney in Scotland, will require smaller and more flexible low investment hydrogen storage sites. Our research shows that the required capacity can exist as engineered geological storage reservoirs onshore and offshore UK. We will give an overview of the hydrogen capacity required for the energy transition and assess the associated scales of storage required, where geological storage in porous media will compete with salt cavern storage as well as surface storage such as line packing or tanks.We will discuss the key aspects and results of subsurface hydrogen storage in porous rocks including the potential reactivity of the brine / hydrogen / rock system along with the efficiency of multiple cycles of hydrogen injection and withdrawal through cushion gasses in porous rocks. We will also discuss societal views on hydrogen storage, exploring how geological hydrogen storage is positioned within the wider context of how hydrogen is produced, and what the place of hydrogen is in a low-carbon society. Based on what some of the key opinion-shapers are saying already, the key considerations for public and stakeholder opinion are less likely to be around risk perception and safety of hydrogen, but focussed on questions like ‘who benefits?’ ‘why do we need hydrogen in a low-carbon society?’ and ‘how can we do this in the public interest and not for the profits of private companies?’We conclude that underground hydrogen storage in porous rocks can be an essential contributor to the low carbon energy transition.

Power plants emit large amounts of carbon dioxide into the atmosphere primarily through the combustion of fossil fuels, leading to accumulation of increased greenhouse gases in the earth’s atmosphere. Global climate changing has led to increasing global mean temperatures, particularly over the poles, which threatens to melt gas hydrate reservoirs, releasing previously trapped methane and exacerbating the situation. Here we used gas hydrate-based technologies to develop techniques for capturing and storing CO2 present in power plant flue gas as stable hydrates, where CO2 replaces methane within the hydrate structure. First, we experimentally measured the thermodynamic properties of various flue gases, followed by modelling and tuning the equations of state. Second, we undertook proof of concept investigations of the injection of CO2 flue gas into methane gas hydrate reservoirs as an option for economically sustainable production of natural gas as well as carbon capture and storage. The optimum injection conditions were found and reaction kinetics was investigated experimentally under realistic conditions. Third, the kinetics of flue gas hydrate formation for both the geological storage of CO2 and the secondary sealing of CH4/CO2 release in one simple process was investigated, followed by a comprehensive investigation of hydrate formation kinetics using a highly accurate in house developed experimental apparatus, which included an assessment of the gas leakage risks associated with above processes. Finally, the impact of the proposed methods on permeability and mechanical strength of the geological formations was investigated.

Solid deposition during production, transport, and storage of crude oils leads to significant technical problems and economic losses for the oil and gas industry. The thermodynamic equilibrium between high-molecular-weight components of crude oil, such as asphaltenes, resins, and waxes, is an important parameter for the stability of crude oil. Once the equilibrium is disturbed due to variations in temperature, pressure, and oil composition during production, the solubility of high-molecular-weight waxes decreases. This results in a decrease in the wax appearance temperature (WAT) and the deposit of wax onto solid surfaces. On the other hand, under these conditions, asphaltenes do not interact sufficiently with the resins/waxes and tend to flocculate among themselves and form asphaltene nanoaggregates. The role of waxes during the asphaltene aggregation and deposition has not been appropriately explained yet. The objective of this research study is to describe the interaction of asphaltenes and waxes and subsequently address the specific example of an asphaltenic oil commingled with a wax inhibitor-containing oil during the combination of different oil streams. It is a crucial building block for the development of a suitable and cost-effective strategy for the handling of wax/asphaltene associated flow assurance problems. In this work, the quartz crystal microbalance (QCM) technique has been used for the first time to investigate the effect of waxes and related chemicals, which are used to mitigate wax deposition, on asphaltene aggregation and deposition phenomena. Asphaltene onset point and asphaltene deposition rate have been monitored using QCM at high pressure–high temperature (HPHT) conditions. This study confirms that the different wax inhibitor chemistries result in significant differences in the pour point decrease and viscosity profiles in crude oil. Different wax inhibitors also showed different outcomes regarding the asphaltene deposition tendency. A comprehensive modeling study has also been conducted for mechanistic investigation of experimental results. In this regard, the perturbed chain statistical associating fluid theory equation of state (PC-SAFT EoS) was utilized to model the systems.

Capturing CO2 from power plant flue gas through hydrate formation is starting to be applied on an industrial scale. Several methods have been developed, and a large number of experiments have been conducted in order to investigate ways of increasing their efficiency. However, most of them suffer from a lack of detailed kinetic studies. In this Letter, we present a highly accurate method to investigate the kinetics of flue gas hydrate formation. Preliminary results are detailed at three different temperatures. It has been found that more than 40% of CO2 capture in the form of hydrates occurs after reaching the final pressure. Therefore, statistically constant pressure cannot be used as a sign of thermodynamic equilibrium. The results obtained from this study are important for optimizing CO2 separation operations thus maximizing efficiency and reducing economic barriers. In addition, they are also useful in studying the kinetics of hydrate formation in other gas mixture systems.

Injection of flue gas or CO2–N2 mixtures into gas hydrate reservoirs has been considered as a promising option for geological storage of CO2. However, the thermodynamic process in which the CO2 present in flue gas or a CO2–N2 mixture is captured as hydrate has not been well understood. In this work, a series of experiments were conducted to investigate the dependence of CO2 capture efficiency on reservoir conditions. The CO2 capture efficiency was investigated at different injection pressures from 2.6 to 23.8 MPa and hydrate reservoir temperatures from 273.2 to 283.2 K in the presence of two different saturations of methane hydrate. The results showed that more than 60% of the CO2 in the flue gas was captured and stored as CO2 hydrate or CO2-mixed hydrates, while methane-rich gas was produced. The efficiency of CO2 capture depends on the reservoir conditions including temperature, pressure, and hydrate saturation. For a certain reservoir temperature, there is an optimum reservoir pressure at which the max...