The mechanisms that affect the long-term fate of carbon dioxide in the subsurface are discussed with an emphasis on pore-scale imaging studies to study capillary trapping and dissolution processes in carbonates. It is shown that capillary trapping can trap a significant fraction of the injected carbon dioxide even in heterogeneous carbonate formations. The extension of the work to carbon dioxide storage into oil fields is discussed. We demonstrate that at near-miscible conditions and in mixed-wet or oil-wet reservoirs the carbon dioxide is intermediate-wet and that water is the most non-wetting phase. The implications for storage and recovery are discussed, as well as suggestions for field-scale modelling of three-phase flow processes.

The bulk of renewable energy production varies in a way that typically does not correspond to time dependent energy consumption. This can lead to an energy surplus or a shortage of the energy supply from renewable energies. To smoothen these supply variations, and enable large scale surplus renewable energy storage, an enormous energy storage capacity is required. Gas as energy carrier, and hence Energy, can be stored in such large amounts in subsurface reservoirs like in depleted gas fields. Especially hydrogen gas is an efficient energy carrier and can be produced from surplus renewable energy.

Session Discussion

CO2 Mineralization in Reactive Rocks

The safest long-term geologic storage of CO2 is its mineralization. Such mineralization is most efficient via the injection of water-dissolved CO2 into mafic or ultramafic rocks. The injection of water dissolved CO2 is shown to be financially favorable. Notably the relative costs of the injection of pure CO2 is found to be similar to that of the dissolution of this CO2 into water as it is injected into the subsurface. This is because the injection of pure CO2 requires higher injection pressures to get the CO2 into subsurface rock formations, owing to its low density, and these higher injection pressures require more robust and costly wells. Such factors tend to balance out the cost of the larger number of wells required for the CO2-charged water injection and the water needed for the dissolution of this gas. This latter cost is reduced if one used seawater rather than freshwater. Once injected into the subsurface this CO2-charged water will react with the subsurface rocks forming both carbonate minerals for the permanent storage of CO2, but also a suite of other secondary mineral products including clay minerals. The choice of target rock formation for CO2-charged water will affect greatly the rate and efficiency of this carbonation process.

Western Saudi Arabia contains a large variety of mafic and ultramafic rock types including fresh and altered basalts, pyroxenites, anorthosites, and altered dunites. Among these altered ultramafic rocks containing substantial brucite will most rapidly carbonate leading to hydromagnesite or magnesite with minor clay mineral formation. In less mafic rocks the presence of aluminum leads to substantial Mg-clay formation, but most of the Ca present in the minerals will be available for mineral carbon storage through the formation of calcite or aragonite. A suite of calculations using a newly constructed mineral kinetic database has been applied to estimating the carbonation rates of subsurface rocks in response to water-dissolved CO2 injections. Results of these calculations provide insight into the relative potential and rates at which each type of rock for the permanent storage of CO2 within these rocks.

The Carbfix consortium has developed methods to capture CO2 from concentrated sources and ambient air and subsequent storage as minerals in basaltic rocks. Mineralisation is the safest way of storing carbon. Before injection via the Carbfix method, CO2 gas is dissolved in water. In the subsurface reservoir, the acidic CO2-charged water releases Ca, Mg and Fe from the basalt, that can combine with the CO2 to form stable carbonate minerals. In the talk we will define the temperature and pressure window for this storage method, which will affect the design of the injection equipment and thus the storage cost. For freshwater applications, the Carbfix method has been tested and applied from 20°C to 270°C. The upper temperature limit is defined by the reaction transforming Ca-carbonates and quartz to wollastonite. Low temperatures, 4°-20°C, slow down the rate of gas-water and water-rock interactions and have not yet been tested in the field. Bacteria activity could affect these processes at 4°-121°C. Seawater contains Ca and SO4, and when injected in areas with a high geothermal gradient, the temperature of injected seawater could rise past 150°C, resulting in anhydrite precipitation within the injection well, which could clog the well over time. Hence, the temperature window for CO2-charged seawater injections is narrower than that for freshwater, around 20°-150°. The pressure window is defined by the injection method and solubility of CO2 in water and seawater. If CO2 is dissolved at low pressure (e.g. 6 bar) in a scrubber on the surface, theoretical depth of a high injectivity well does not need to be deeper than 100 -200 m. If CO2 is dissolved within the injection well, the preferred gas pressure is around 25 bar at 25°C. This requires a minimum of 250 m water column above to point of gas release in the well, and a similar downhole distance of about 250 m for the kinetic driven dissolution of the down-going gas bubbles. Thus, the depth of the injection well has to be > 500 m. Once the gas bubbles are dissolved in the injection water, it is denser than the formation water, and has the tendency to sink. If the transmissivity of the well is good, there is no need to pressurize the injected water.

Storing CO2 in reactive igneous rocks (eg basalt) is an emerging carbon capture and storage (CCS) technology with a significant global GHG mitigation potential. In contrast to physically storing CO2 in sedimentary reservoirs, CO2 storage in basalts (CSB) relies on the rapid and permanent chemical carbonation of CO2 to minerals (calcite). CSB has been studied and successfully applied on an industrial scale at the Hellischeidi power plant in Iceland since 2014 (ie CarbFix1 & 2). In this presentation we will discuss the CO2 sequestration potential of reactive igneous rocks in western Saudi Arabia. We will focus on the petrolological and mineralogical properties of selected geological units, which outcrop in the vicinity major stationary CO2 sources near Yanbu, Rabigh, Jeddah, Madinah and Jazan, with an emphasis of the implications of these on the CO2 storage potential of the different reactive rock types. We will also present a preliminary estimate on the potential volumes of CO2 each of these units may be able to sequester.

Hydrogen is receiving global attention and significant market momentum as a future low-carbon energy vector. Blue hydrogen is, therefore, critical to addressing carbon emission reduction and sustainable use of hydrocarbons in transport and power sectors. This presentation will highlight fuel flexible reforming technology to produce hydrogen from hydrocarbon feedstocks while capturing the CO2 generated during the process. Long distance transport of hydrogen is one of the key challenges in establishing global hydrogen supply chain. Ammonia is one of the promising hydrogen carriers due to its high gravimetric hydrogen density, relatively mild storage conditions as a liquid, and proven and well-established trans-ocean transport. The presentation will highlight a recent successful demonstration of blue ammonia supply chain pilot from KSA to Japan by Saudi Aramco and its project partners.

The future for hydrogen looks brighter than ever, even though the world is experiencing some dark days. An increased focus on environmental issues, technology breakthroughs and improving economics are making the once fanciful idea of a Hydrogen Economy much more tangible. Positive signals concerning the transition to zero emissions vehicles and other demand changes are getting nations around the world to seriously consider hydrogen as an alternative energy vector and a possible business opportunity.

Carbon capture and storage (CCS) has emerged as one of the key technologies for the abatement of CO2 emissions, and meeting the energy demands in a carbon-constrained world, especially in the context of negative-emissions technologies. Two issues, however, have emerged as critical to ensure safe and effective geologic CO2 storage:

The Paris Agreement aim for limiting warming to 1.5 C relies on the assumption that Carbon Capture and Storage will be broadly deployed to reach the Net-Zero emission by 2050. In the last two decades, CO2 storage in saline aquifers has been studied extensively; however, there is an uncertainty with small-scale features just beneath the caprock (surface rugosity and heterogeneity), which will not be identified by seismic data, that could have an effect on plume migration at the top of the storage formation. Thus, considering such effects in a real case scenario such as Sleipner could help further in the prediction of CO2 plume behaviour beneath the caprock. We have investigated the impact of top surface morphology on plume migration using outcrop data in the UK (Sherwood Sandstone Group) then performed a numerical simulation study to examine the impact of reservoir–caprock topography on CO2 plume migration in comparison to other uncertain parameters such as porosity, permeability, reservoir temperature, reservoir pressure and injection rate in the Sleipner using the 2019 Benchmark model.

Geological sequestration of carbon dioxide (CO2) in underground formations is the most promising way to decrease the greenhouse emissions into atmosphere. The understanding of long term effects of CO2 storage in carbonate aquifers is challenged by many uncertainties including geochemical effects of CO2 on carbonates and the coupled chemical–mechanical effects.

Injection of CO2 into deep saline aquifers leads to a flow system of two fluid phases—injected CO2 and resident brine—that requires modeling tools to simulate migration of both fluids. While high-fidelity full three-dimensional (3D) multiphase flow models are available, their application for practical analysis remains challenging due to the high computational costs and the significant uncertainty of subsurface geological parameters.

As an IEA Technology Collaboration Programme, IEAGHG has an active interest in the technology roll-out of CCS including the development of innovative concepts such as evaluating potential synergies between geothermal energy and CCS including CO2 geological storage. There is growing interest in both technologies especially with the prospect of significant advances towards full-scale multi-million tonne CO2 storage sites. As a former programme manager of the UK’s geothermal R&D programme I would like to give a personal perspective on the outcome of that programme and how it might relate to new opportunities including prospects for Saudi Arabia. Recent developments in the use of CO2 in geothermal energy will be reviewed and how they might be related to Saudi Arabia.

GECO is an innovative project aiming at offering clean geothermal energy with a lower cost. It builds upon the success of the recently completed CARBFIX project.

CO2-rock wettability is a key factor which strongly influences CO2 containment security and storage capacity in the context of CO2 geo-sequestration projects. It is thus vital to understand this parameter in detail. Here the variation of CO2-rock wettability will be demonstrated, and underlying mechanisms will be discussed. Clearly, rock surface chemistry is the prime factor which determines CO2 wettability, while pressure, temperature and brine salinity also play a significant role. Finally, the impact of CO2-wettability at larger (reservoir) scale is illustrated. This talk will thus improve the understanding of a fundamental technical parameter and aid in the larger-scale implementation of CO2 geo-storage schemes.

The storage of CO2 in depleted oil reservoirs, while recovering substantial oil through enhanced oil recovery (EOR) is one way to reduce the amount of CO2 in our atmosphere. For this coupling to be effective, the focus should shift from minimizing CO2 utilization factors to injection of significant CO2 volumes, while reducing CO2 production and maximizing oil recoveries.

This presentation focuses on experimental/simulation studies on the ability of organic-rich core samples to store carbon dioxide. I will begin with a quick review of CO2 behavior in organic nanopores under subsurface conditions using molecular simulations. To measure the storage capacity of the rock samples in the laboratory, an apparatus has been built and a new analytical method is developed allowing interpretation of the pressure/volume data in terms of measurements of total porosity and Langmuir parameters of core plugs under effective stress.

CCUS stands for Carbon Capture, Utilization and Storage. Too often, it is interpreted to mean “Carbon dioxide” Capture, Utilization and Storage; this may lead to a constraint on the imagination, leading to a reluctance to assess other potential pathways to achieve the goals of atmospheric emissions reductions. Several “unconventional” CCUS pathways are discussed here, perhaps helping to trigger ideas that may lie outside of the conventional pathway of “CO2 capture, compression and injection”, whether for EOR or direct sequestration. Furthermore, only direct sequestration will be addressed here.

Depleted hydrocarbon fields represent attractive storage options for CO2. Their attractiveness arises from the presence of a proven trap, the knowledge about the field from the production period and the potential opportunity to re-use production assets for the injection of CO2. The fields also offer challenges, such as those related to legacy wells and to the low reservoir pressure after production. This presentation focuses on the impact of low depletion pressures on feasible injection rates in either existing or new wells. The conditions in the reservoir and the phase of the CO2 during injection (gas phase, liquid phase) determine the operational window of a well. In some cases, a well can have a minimum flow rate, below which the conditions in the well may lead to well integrity risks. While such results impact the design of a storage operation in a depleted field and also the development of a storage network, they also point the way towards tuning well designs to meet CO2 supply profiles.

Given allowable carbon emissions for reaching climate targets, CCS and CCUS are without alternatives to simultaneously maintain a supply of sufficient energy for the world and preventing stranded subsurface assets for hydrocarbon producing countries. Permanent storage of carbon dioxide (CO2) in deep subsurface formations is acknowledged as a scalable and achievable technology to contribute to the ongoing efforts of limiting CO2 emissions and possibly lead to the use of stored CO2 for geothermal energy generation.

Carbon storage is considered to be a necessary technology in bridging the transition to a low carbon energy mix. Environmental risks related to the geological storage of CO2 such as well leakage, fault reactivation, seismicity and caprock failure, need to be minimized. In this work, we developed a probabilistic model to assess the risk of cement sheath failure and the associated well leakage. The approach integrates a finite element model for well integrity analysis with a probabilistic model based on Bayesian Belief Networks (BBN).

Subsurface geological formations provide giant capacities for storing not only greenhouse gases (e.g. carbon dioxide) but also renewable energy, when it is converted into green gas (e.g., hydrogen) or compressed and hot fluids. While the utilisations of subsurface formations for greenhouse gas storage have extensively studied in the past decades, their successful contribution for cyclic green energy storage comes with new scientific challenges too. Hydrogen is expected not only to be stored safely, but to be reclaimed efficiently and with the same purity as in the injection phase. The critical stress also will impose restrictions on the volume, rate, and frequency of the storage cycles. In this talk, I will present the recent advancements from laboratory characterization to pore-scale and reservoir-scale modelling of hydrogen storage; built on our gained knowledge from CO2 storage projects.

To verify successful long-term carbon dioxide storage, an improved understanding of geological leakage risks across the primary caprock but also the shallower overburden is critical. While diffusive and advective matrix leakage can be considered to take place at low to moderate rates, especially fault-related fracture networks require an improved understanding. Faults can act as flow barriers and traps in reservoirs but also as leakage pathways into the shallow overburden. Being able to fully characterise fault and fracture networks, in terms of fracture permeability, fracture density, connectivity, aperture size and stress regime, can allow us to more accurately identify, analyse and model the bulk properties (e.g. transport, strength, anisotropy) and, therefore sealing behaviour, of faulted and fractured geological storage sites.

Geological sequestration of CO2 requires knowledge of the flow properties of fault-related fracture networks in the low-permeability shale caprocks that overly most of the considered storage sites. A safe, sustainable and economical storage operation requires a profound understanding of these risks, recognising that quantification is challenging due to the many length and time scales involved and the very limited availability of data. These risks were addressed in the ACT project DETECT: Determining the risk of CO2 leakage along fractures of the primary caprock using an integrated monitoring and hydro-mechanical-chemical approach and the ERC project SECURe: Subsurface Evaluation of CCS and Unconventional Risks.