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Summary Following the landmark 2015 United Nations Paris Agreement, a growing number of countries are committing to the transition to net-zero emissions. Carbon capture and storage (CCS) has been consistently heralded to directly address emissions from the energy and industrial sectors and forms a significant component of plans to reach net-zero. However, despite the critical importance of the technology and substantial research and development to date, CCS deployment has been slow. This review examines deployment efforts over the last decade. We reveal that facility deployment must increase dramatically from current levels, and much work remains to maximize storage of CO2 in vast subsurface reserves. Using current rates of deployment, CO2 storage capacity by 2050 is projected to be around 700 million tons per year, just 10% of what is required. Meeting the net-zero targets via CCS ambitions seems unlikely unless worldwide coordinated efforts and rapid changes in policy take place.

Decarbonising the residential heating and cooking sector is essential to meet national and international carbon emission reduction targets. Hydrogen has been identified by the scientific community, industry, and policy makers as part of the solution to this challenge. Hydrogen has been used for decades in many industries, formerly making up approximately 50% of the Town Gas used for heating and cooking in UK homes in the mid 20th century. It is now crucial to ensure safety regulations are met, and public acceptance gained, before hydrogen can start being used for residential heating. Demonstration projects require hydrogen distribution networks to be odorised. This study examines the use of sulphur-based odorants, which are currently in use in the UK and Europe to odorise Natural Gas, to be used in a 100% hydrogen gas demonstration network in the UK. We undertook a comparative testing programme to evaluate the escape detection properties of odorised hydrogen against odorised methane and natural gas. This comparative approach will help address the question asked by UK and EU regulators: is hydrogen ‘as safe as’ natural gas? The results show that untrained participants can identify an escaping gas odorised with Odorant New Blend and standby odorant 2, in hydrogen, natural gas or methane, at the regulatory threshold of 1% gas in air. These results contribute to the safety-case of H100 led by SGN.

Increased penetration of renewable energy sources and decarbonisation of the UK's gas supply will require large-scale energy storage. Using hydrogen as an energy storage vector, we estimate that 150 TWh of seasonal storage is required to replace seasonal variations in natural gas production. Large-scale storage is best suited to porous rock reservoirs. We present a method to quantify the hydrogen storage capacity of gas fields and saline aquifers using data previously used to assess CO2 storage potential. We calculate a P50 value of 6900 TWh of working gas capacity in gas fields and 2200 TWh in saline aquifers on the UK continental shelf, assuming a cushion gas requirement of 50%. Sensitivity analysis reveals low temperature storage sites with sealing rocks that can withstand high pressures are ideal sites. Gas fields in the Southern North Sea could utilise existing infrastructure and large offshore wind developments to develop large-scale offshore hydrogen production.

Meeting inter-seasonal fluctuations in electricity production or demand in a system dominated by renewable energy requires the cheap, reliable and accessible storage of energy on a scale that is currently challenging to achieve. Commercially mature compressed-air energy storage could be applied to porous rocks in sedimentary basins worldwide, where legacy data from hydrocarbon exploration are available, and if geographically close to renewable energy sources. Here we present a modelling approach to predict the potential for compressed-air energy storage in porous rocks. By combining this with an extensive geological database, we provide a regional assessment of this potential for the United Kingdom. We find the potential storage capacity is equivalent to approximately 160% of the United Kingdom’s electricity consumption for January and February 2017 (77–96 TWh), with a roundtrip energy efficiency of 54–59%. This UK storage potential is achievable at costs in the range US$0.42–4.71 kWh−1. Compressed-air energy storage could be a useful inter-seasonal storage resource to support highly renewable power systems. This study presents a modelling approach to assess the potential for such storage in porous rocks and, applying it to the UK, finds availability of up to 96 TWh in offshore saline aquifers.

Carbon Capture and Storage (CCS) is an essential tool in the fight against climate change. Any prospective storage site must meet various criteria that ensure the effectiveness, safety and economic viability of the storage operations. Finding the most suitable site for the storage of the captured CO2 is an essential part of the CCS chain of activity. This work addresses the site selection of a second site for the Acorn CCS project, a project designed to develop a scalable, full-chain CCS project in the North Sea (offshore northeast Scotland). This secondary site has been designed to serve as a backup and upscaling option for the Acorn Site, and has to satisfy pivotal project requirements such as low cost and high storage potential. The methodology followed included the filtering of 113 input sites from the UK CO2Stored database, according to general and project-specific criteria in a multi-staged approach. This criteria-driven workflow allowed for an early filtering out of the less suitable sites, followed by a more comprehensive comparison and ranking of the 15 most suitable sites. A due diligence assessment was conducted of the top six shortlisted sites to produce detailed assessment of their storage properties and suitability, including new geological interpretation and capacity calculations for each site. With the new knowledge generated during this process, a critical comparison of the sites led to selection of East Mey as the most suitable site, due to its outstanding storage characteristics and long-lasting hydrocarbon-production history, that ensure excellent data availability to risk-assess storage structures. A workshop session was held to present methods and results to independent stakeholders; feedback informed the final selection criteria. This paper provides an example of a criteria-driven approach to site selection that can be applied elsewhere., Project ACT-Acorn is gratefully thanked for funding this study. ACT Acorn, project 271500, received funding from BEIS (UK), RCN (Norway) and RVO (Netherland), and was co-funded by the European Commission under the ERA-Net instrument of the Horizon 2020 programme. ACT Grant number 691712. J. Alcalde is funded by MICINN (Juan de la Cierva fellowship - IJC2018-036074-I). S. Ghanbari is currently supported by the Energi Simulation. Energi Simulation is also thanked for funding the chair in reactive transport simulation held by E. Mackay.

Research to date has identified cost and lack of support from stakeholders as two key barriers to the development of a carbon dioxide capture and storage (CCS) industry that is capable of effectively mitigating climate change. This paper responds to these challenges through systematic evaluation of the research and development process for the Acorn CCS project, a project designed to develop a scalable, full-chain CCS project on the north-east coast of the UK. Through assessment of Acorn's publicly-available outputs, we identify strategies which may help to enhance the viability of early-stage CCS projects. Initial capital costs can be minimised by infrastructure re-use, particularly pipelines, and by re-use of data describing the subsurface acquired during oil and gas exploration activity. Also, development of the project in separate stages of activity (e.g. different phases of infrastructure re-use and investment into new infrastructure) enables cost reduction for future build-out phases. Additionally, engagement of regional-level policy makers may help to build stakeholder support by situating CCS within regional decarbonisation narratives. We argue that these insights may be translated to general objectives for any CCS project sharing similar characteristics such as legacy infrastructure, industrial clusters and an involved stakeholder-base that is engaged with the fossil fuel industry. © 2019, The authors want to thank the entire ACT Acorn team for their support. The ACT Acorn project was funded by Accelerating CCS Technologies under Horizon 2020. Alcalde is currently funded by EIT Raw Materials – SIT4ME project (17024).

The deployment of Carbon Capture and Storage (CCS) is recognised as critical to delivering deep decarbonisation of energy and industrial processes. CCS clusters, where multiple CO2 emitting sources share CO2 transport and storage infrastructures, offer cost savings and enable smaller sources to undertake CCS, which are unlikely to be capable of justifying a stand-alone transport and storage system. Scotland has a legacy of onshore and offshore pipelines, which transported methane from producing regions. These can be re-used to connect CO2 emitters to storage. Approximately 80% of large point-source CO2 emissions in Scotland are within 40 km of the Feeder 10 pipeline. Thirteen selected emitters are evaluated for potential CO2 capture volume, estimated capture project cost and cost of connection. Scenarios for sequential deployment show that Feeder 10 has capacity through known expansion potential for developments allowing capture volumes rising from 2 to 8 Mt yr−1 CO2.

For carbon capture and storage to successfully contribute to climate mitigation efforts, the captured and stored CO2 must be securely isolated from the atmosphere and oceans for a minimum of 10,000 years. As it is not possible to undertake experiments over such timescales, here we investigate natural occurrences of CO2, trapped for 104 -106 yr to understand the geologic controls on long term storage performance. We present the most comprehensive natural CO2 reservoir dataset compiled to date, containing 76 naturally occurring natural CO2 stores, located in a range of geological environments around the world. We use this dataset to perform a critical analysis of the controls on long-term CO2 retention in the subsurface. We find no evidence of measureable CO2 migration at 66 sites and hence use these sites as examples of secure CO2 retention over geological timescales. We find unequivocal evidence of CO2 migration to the Earth’s surface at only 6 sites, with inconclusive evidence of migration at 4 reservoirs. Our analysis shows that successful CO2 retention is controlled by: thick and multiple caprocks, reservoir depths of >1200m, and high density CO2. Where CO2 has migrated to surface, the pathways by which it has done so are focused along faults, illustrating that CO2 migration via faults is the biggest risk to secure storage. However, we also find that many naturally occurring CO2 reservoirs are fault bound illustrating that faults can also securely retain CO2 over geological timescales. Hence, we conclude that the sealing ability of fault or damage zones to CO2 must be fully characterised during the appraisal process to fully assess the risk of CO2 migration they pose. We propose new engineered storage site selection criteria informed directly from on our observations from naturally occurring CO2 reservoirs. These criteria are similar to, but more prescriptive than, existing best-practise guidance for selecting sites for engineered CO2 storage and we believe that if adopted will increase CO2 storage security in engineered CO2 stores.

Carbon capture and storage (CCS) does not generate energy. CCS applied to fossil and modern bio-carbon fuels and feedstocks removes environmentally damaging CO2 emissions. CoP21 stipulated a maximum 2°C–1.5°C global warming from 2050 in perpetuity. Both CCS and negative emission technology (NET) are now required to manage the carbon stock in earth’s atmosphere and oceans. All components of CCS are operationally proven secure at the industrial scale. Fifteen CCS projects operate globally; seven are under construction. CCS systems increase electricity prices, to about £100/MWhr. CCS on industry is cheaper and storage costs minimal (£5–20/tonne). CCS reduces whole economy costs of carbon transition by 2.5 times. Policies of capex subsidy, oversupplied emissions certificates, weak carbon pricing, and weak emissions standards have all failed to develop large cost CCS mega-projects. New carbon certificates could link the extraction of carbon to an obligation to store a percentage of emissions. Certificates connect CCS and NET pathways to secure carbon storage for the public good.

The useful energy services and energy density value of fossil carbon fuels could be retained for longer timescales into the future if their combustion is balanced by CO2 recapture and storage. We assess the global balance between fossil carbon supply and the sufficiency (size) and capability (technology, security) of candidate carbon stores. A hierarchy of value for extraction-to-storage pairings is proposed, which is augmented by classification of CO2 containment as temporary (100,000 yr). Using temporary stores is inefficient and defers an intergenerational problem. Permanent storage capacity is adequate to technically match current fossil fuel reserves. However, rates of storage creation cannot balance current and expected rates of fossil fuel extraction and CO2 consequences. Extraction of conventional natural gas is uniquely holistic because it creates the capacity to re-inject an equivalent tonnage of carbon for storage into the same reservoir and can re-use gas-extraction infrastructure for storage. By contrast, balancing the extraction of coal, oil, biomass and unconventional fossil fuels requires the engineering and validation of additional carbon storage. Such storage is, so far, unproven in sufficiency.

There is a projected shortcoming in the fourth carbon budget of 7.5%. This shortfall may be increased if the UK pursues a domestic shale gas industry to offset projected decreases in traditional gas supply. Here we estimate that, if the project domestic gas supply gap for power generation were to be met by UK shale gas with low fugitive emissions (0.08%), an additional 20.4 Mt CO 2 e 1 would need to be accommodated during carbon budget periods 3–6. We find that a modest fugitive emissions rate (1%) for UK shale gas would increase global emissions compared to importing an equal quantity of Qatari liquefied natural gas. Additionally, we estimate that natural gas electricity generation would emit 420–466 Mt CO 2 e (460 central estimate) during the same time period within the traded EU emissions cap. We conclude that domestic shale gas production with even a modest 1% fugitive emissions rate would risk exceedance of UK carbon budgets. We also highlight that, under the current production-based greenhouse gas accounting system, the UK is incentivized to import natural gas rather than produce it domestically.

In recent years, Carbon Capture and Storage (Sequestration) (CCS) has been proposed as a potential method to allow the continued use of fossil-fuelled power stations whilst preventing emissions of CO2 from reaching the atmosphere. Gas, coal (and biomass)-fired power stations can respond to changes in demand more readily than many other sources of electricity production, hence the importance of retaining them as an option in the energy mix. Here, we review the leading CO2 capture technologies, available in the short and long term, and their technological maturity, before discussing CO2 transport and storage. Current pilot plants and demonstrations are highlighted, as is the importance of optimising the CCS system as a whole. Other topics briefly discussed include the viability of both the capture of CO2 from the air and CO2 reutilisation as climate change mitigation strategies. Finally, we discuss the economic and legal aspects of CCS.

Multi-user storage systems are anticipated in the near future to permanently store CO2 captured at industrial sources to meet emissions reductions targets. Multiple storage permit applications will be required to exploit the immense potential capacity within extensive CO2 storage assets. To retain 99% of the injected CO2 for 1000 years the geomechanical stability of the sealing strata above the pressurised storage reservoir is a key factor which needs to be included in the geo-engineering design of shared storage assets The potential for interaction of increased pressure at multiple injection sites needs to be predicted and assessed at a regional scale to assure the integrity at all existing sites before a storage permit is granted. Geomechanical models coupled with the expected fluid pressure response predict the stability of the storage asset during and after injection of CO2 at multiple injection sites, and can be used as a tool to ensure efficient utilisation of the storage capacity. The geomechanical analysis of the thermal stress as well as local and regional fluid pressure changes requires a detailed numerical evaluation, often at a resolution significantly higher than the data available. Coupling of regional-scale static geological models, dynamic multi-phase flow models and detailed geomechanical models requires extensive computational resources. Such models often produce seemingly detailed results, but are usually only one or two realisations of a system populated by a statistically generated parameter set. Limits on time and computational resources prevent more simulations within fixed time and financial budgets. To enable a more time and cost efficient methodology of assessing the geomechanical stability of potential storage sites we present a four-tier modelling approach with increasing complexity that allows an in-depth evaluation of the geomechanical stability at a regional scale of a multi-user storage asset taking into account the fluid pressure increase and the thermal stress impact on the stability of the strata sealing the CO2 store. The tiers include: (1) development of a geo-mechanical facies model of the storage system, (2) development of an analytical geomechanical model for the storage site static stress conditions, (3) fitting an empirical multivariable polynomial function to the analytical modal, and (4) conditioning the empirical function using coupled numerical THM modelling for dynamic stress conditions. The result is look up function which gives the maximum possible fluid pressure as a function of location. This approach significantly simplifies the computational requirements and time for the prediction of geomechanical behaviour. In addition to presenting this methodology, using the Captain Sandstone of the North Sea as an example, three key findings are further examined. Firstly, detailed analysis of the stress changes as a result of cold fluid injection suggests that the redistribution of thermal stress can, in some cases, be beneficial to the storage system depending on the stress bridging which occurs. Secondly, pressure plume migration over time in dipping strata, from deeper injection sites to shallower sites, needs to be taken into account. Thirdly, the nature of the strata underlying the storage formation is critical to the pressure increase in response to the fluid injection. The methodology developed in this paper enables a rapid and efficient screening of the dynamic geomechanical stability and facilitates an efficient coupling to diverse discrete multiphase fluid flow models using commonly available computational resources.

The principles of hydrocarbon exploration and production provide well-established and tested principles and technologies to investigate storage of fluids in the subsurface. CO2 can be stored in the subsurface using settings of: (A) thick permeable coal seams; (B) depleted oil and gas fields; (C) saline aquifers of regional extent, with an overlying seal. The North Sea Sleipner project shows that CO2 can be injected into the pore space of deep geological aquifers deeper than 800 m at 1 Mt/yr, using established technology. Suitable sediment sequences of saline aquifers exist in all hydrocarbon- producing areas, are volumetrically much larger than exploited oil and gas fields, and hold the potential to easily store all worldwide CO2 emissions until 2050. Geological principles are established to assess entire continents for candidate sites of CO2 storage. This shows that opportunity may be widespread, but needs more specific local investigations. Onshore sub-Saharan Africa is considered the most problematic region - but even here there are potentially viable sediment sequences. No demonstration projects currently exist for CO2 capture and storage using small-scale onshore facilities. A simple estimate, assuming CO2 value of $20 per ton, suggests that single boreholes onshore may be viable over 20 years with supply rates of 100,000 ton CO2 per year. In principle, atmospheric CO2 could be captured by cultivated biomass, and co-fired in existing power stations. Or energy crops could be grown, CO2 to be used, and stored deep below ground, in a country distant from an original fossil-fuel CO2 emission site.

To re-establish global climate balance, it is necessary to remove large amounts of fossil carbon emitted by humans, which is currently located in the atmosphere and the upper ocean. Although great attention is given to technologies of capture, the ability to store immense tonnages of carbon stock for geologically long time periods, isolated from atmosphere and ocean interaction, is equally important. In this chapter, the multiple storage locations for carbon stocking on and below land, also within and below the ocean, are evaluated. The evaluation shows that carbon dioxide reduction (CDR) is useful for mitigation, but cannot balance the rate of new emissions from fossil fuel exploitation. Many CDR methods have large uncertainty in their quantity, life-cycle, global impact and engineered feasibility. Competition for biomass and land usage is inevitable. Pathways and reservoirs of carbon in the ocean are complex and interlocked. Engineered storage of carbon will also be expensive, resource intensive and cannot substitute for a greatly reduced usage of fossil carbon. Human industrial and economic activity must “move beyond hydrocarbons” to be sustainable beyond 2050.

Industrialized societies which continue to use fossil fuel energy sources are considering adoption of Carbon Capture and Storage (CCS) technology to meet carbon emission reduction targets. Deep geological storage of CO 2 onshore faces opposition regarding potential health effects of CO 2 leakage from storage sites. There is no experience of commercial scale CCS with which to verify predicted risks of engineered storage failure. Studying risk from natural CO 2 seeps can guide assessment of potential health risks from leaking onshore CO 2 stores. Italy and Sicily are regions of intense natural CO 2 degassing from surface seeps. These seeps exhibit a variety of expressions, characteristics (e.g., temperature/flux), and location environments. Here we quantify historical fatalities from CO 2 poisoning using a database of 286 natural CO 2 seeps in Italy and Sicily. We find that risk of human death is strongly influenced by seep surface expression, local conditions (e.g., topography and wind speed), CO 2 flux, and human behavior. Risk of accidental human death from these CO 2 seeps is calculated to be 10-8 year-1 to the exposed population. This value is significantly lower than that of many socially accepted risks. Seepage from future storage sites is modeled to be less that Italian natural flux rates. With appropriate hazard management, health risks from unplanned seepage at onshore storage sites can be adequately minimized.

Governments worldwide should provide incentives for initial large-scale GS projects to help build the knowledge base for a mature, internationally harmonized GS regulatory framework. Health, safety, and environmental risks of these early projects can be managed through modifications of existing regulations in the EU, Australia, Canada, and the U.S. An institutional mechanism, such as the proposed Federal Carbon Sequestration Commission in the U.S., should gather data from these early projects and combine them with factors such as GS industrial organization and climate regime requirements to create an efficient and adaptive regulatory framework suited to large-scale deployment. Mechanisms to structure long-term liability and fund long-term postclosure care must be developed, most likely at the national level, to equitably balance the risks and benefits of this important climate change mitigation technology. We need to do this right. During the initial field experiences, a single major accident, resulting from inadequate regulatory oversight, anywhere in the world, could seriously endanger the future viability of GS. That, in turn, could make it next to impossible to achieve the needed dramatic global reductions in CO2 emissions over the next several decades. We also need to do it quickly. Emissions are going up, the climate is changing, and impacts are growing. The need for safe and effective CO2 capture with deep GS is urgent.

India is a nation with a rapidly growing economy, achieving an 8.5% GDP growth rate in 2006 and 9.2% in 2007. This rise in economic growth goes hand in hand with an increase in the country’s energy demand, which is currently met, as in many evolving economies, by fossil fuels. Coal is the dominant commercial fuel, accounting for almost 70% of the total energy consumption, but India still faces serious electricity shortfalls. Both the Stern Review and The International Energy Agency’s World Energy Outlook reports have listed Carbon Capture and Storage (CCS) as a carbon mitigation strategy for India. It is unclear, if, how, or when, CCS will have a place within the Indian system.