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Decarbonisation of transport emissions is essential to meet climate targets. For road transport, currently available technologies are battery electric vehicles and hydrogen fuel cell electric vehicles. Battery vehicles are more established than hydrogen; both could deliver the emissions reduction required. However, battery vehicles are considerably heavier than equivalent hydrogen vehicles, which are in turn slightly heavier than internal combustion engine (ICE) vehicles; a heavier vehicle will have a bigger impact on road wear and associated costs. Here we carry out a desk-based analysis, developed in 2021–2022, examining the impact and cost of the increased weight of zero emissions vehicles on road wear in an entire national vehicle fleet. The novelty is in the first quantified application of the long-understood relationship between axle load and road wear to the problem of the additional weight of zero emissions vehicles. This leads to an approximate quantification of additional costs of road maintenance as the vehicle fleet transitions to zero emissions vehicles. We examine these in four scenarios: all battery vehicles; all hydrogen vehicles; a combination; current ICE vehicles for comparison. We find 20–40% additional road wear associated with battery vehicles compared to ICE vehicles; hydrogen leads to a 6% increase. This is overwhelmingly caused by large vehicles – buses, heavy goods vehicles. Smaller vehicles make a negligible contribution. Governmental bodies liable for road maintenance may wish to set weight limits on roads, require additional axles on heavier vehicles, or construct new roads to a higher standard, to decrease road wear. Graphical abstract

Alternatively known as greenhouse gas removal (GGR), carbon dioxide removal (CDR), or negative emissions technology (NET), the concept of removing greenhouse gases (GHGs)—primarily CO2—from the atmosphere has been gaining increasing academic, industrial, financial, and political attention over recent years as corporate and national commitments to net-zero targets proliferate. Practically all pathways to net zero include essential contributions from NET, typically 10%–20% of current national emissions

Current commercially available options for decarbonisation of road transport are battery electric vehicles or hydrogen fuel cell electric vehicles. BEVs are increasingly deployed, while hydrogen is in its infancy. We examine the infrastructure necessary to support hydrogen fuelling to various degrees of market penetration. Scotland makes a good exemplar of transport transition, with a world leading Net-Zero ambition and proven pathways for generating ample renewable energy.We identified essential elements of the new transport systems and the associated capital expenditure. We developed nine scenarios based on the pace of change and the ultimate market share of hydrogen, and constructed a model to analyse their infrastructure requirements. This is a multi-period model, incorporating Monte Carlo and Markov Chain elements.A “no-regrets” initial action is rapid deployment of enough hydrogen infrastructure to facilitate the early years of a scenario where diesel fuel becomes replaced with hydrogen. Even in a lower demand scenario of only large and heavy goods vehicles using hydrogen, the same infrastructure would be required within a further two years. Subsequent investment in infrastructure could be considered in the light of this initial development.

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.

Secure retention of CO2 in geological reservoirs is essential for effective storage. Solubility trapping, the dissolution of CO2 into formation water, is a major sink on geological timescales in natural CO2 reservoirs. Observations during CO2 injection, combined with models of CO2 reservoirs, indicate the immediate onset of solubility trapping. There is uncertainty regarding the evolution of dissolution rates between the observable engineered timescale of years and decades, and the >10 kyr state represented by natural CO2 reservoirs. A small number of studies have constrained dissolution rates within natural analogues. The studies show that solubility trapping is the principal storage mechanism after structural trapping, removing 10–50% of CO2 across whole reservoirs. Natural analogues, engineered reservoirs and model studies produce a wide range of estimates on the fraction of CO2 dissolved and the dissolution rate. Analogue and engineered reservoirs do not show the high fractions of dissolved CO2 seen in several models. Evidence from natural analogues supports a model of most dissolution occurring during emplacement and migration, before the establishment of a stable gas–water contact. A rapid decline in CO2 dissolution rate over time suggests that analogue reservoirs are in dissolution equilibrium for most of the CO2 residence time. Supplementarymaterial: Dissolution rate for all plots and exponential function curves for scenarios A and B are available at https://doi.org/10.6084/m9.figshare.c.5476199 Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

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.

Mineral trapping of CO2 by precipitation of carbonate minerals is seen as the most permanent and secure mechanism of CO2 storage. We have investigated mineral trapping in CO2-rich siliciclastic reservoirs of the Upper Miocene age in the Yinggehai Basin (South China Sea) and used nearby CO2-poor reservoirs of similar age as benchmarks for the analysis. Within the reservoir, the CO2 has triggered the reaction from calcite plus chlorite to ankerite plus kaolinite, which traps 5 mol of CO2 per mole of chlorite. Geochemical modelling shows that the total amount of permanently trapped CO2 is approximately one half of the CO2 in the newly formed ankerite. Caprock mineralogy shows that CO2 leakage has occurred and CO2 has migrated into the shale-rich caprock, but without loss of caprock integrity.

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.

As the Paris Agreement moves towards implementation, we explore opportunities it presents to move part of the climate change mitigation challenge upstream into supply-side climate policy. Supply-side climate policies have been sparsely employed to date, although interest is growing in approaches that can curtail and end fossil fuel production. Rather than focussing on fully eliminating fossil fuel production, we set out an alternative supply-side approach that involves fossil fuel producers taking progressive action to reduce and eliminate the climate impacts of their products. Our proposal uses the Paris Agreement’s framework for finance and international cooperation to establish supply-side climate action that supplements demand-side climate policies, and thereby enhance climate ambition. The concepts presented rely on large-scale geosequestration technologies that can deposit carbon into geological reservoirs at rates progressively aligned to those at which carbon is being extracted by fossil fuel producers. Convergence of extraction and deposition rates is a necessary condition for achieving net-zero CO2 emissions while still enabling some essential uses of fossil carbon. We propose an evolutionary approach to policy development, starting as a technology-support mechanism using results-based finance before transitioning into systematic measures under, firstly, Article 6 of the Paris Agreement, and, ultimately, decarbonised fuel standards. Collectively these could incentivise fossil fuel resource holders to manage both outflows and inflows of carbon in the geosphere, and in doing so, create, foster, accelerate and maintain an urgently needed market for geological CO2 storage.

Petroleum-rich basins at a mature stage of exploration and production offer many opportunities for large-scale Carbon Capture and Storage (CCS) since oil and gas were demonstrably contained by low-permeability top-sealing rocks, such as shales. For CCS to work, there must be effectively no leakage from the injection site, so the nature of the top-seal is an important aspect for consideration when appraising prospective CCS opportunities. The Lower Cretaceous Rodby Shale and the Palaeocene Lista Shale have acted as seals to oil and gas accumulations (e.g., the Atlantic and Balmoral fields) and may now play a critical role in sealing the Acorn and East Mey subsurface carbon storage sites. The characteristics of these important shales have been little addressed in the hydrocarbon extraction phase, with an understandable focus on reservoir properties and their influence on resource recovery rates. Here, we assess the characteristics of the Rodby and Lista Shales using wireline logs, geomechanical tests, special core analysis (mercury intrusion) and mineralogical and petrographic techniques, with the aim of highlighting key properties that identify them as suitable top-seals. The two shales, defined using the relative gamma log values (or Vshale), have similar mean pore throat radius (approximately 18 nm), splitting tensile strength (approximately 2.5 MPa) and anisotropic values of splitting tensile strength, but they display significant differences in terms of wireline log character, porosity and mineralogy. The Lower Cretaceous Rodby Shale has a mean porosity of approximately 14 %, a mean permeability of 263 nD (2.58 &times, 10&minus, 19 m2), and is calcite rich and has clay minerals that are relatively rich in non-radioactive phases such as kaolinite. The Palaeocene Lista Shale has a mean porosity of approximately 16% a mean permeability of 225 nD (2.21 &times, 19 m2), and is calcite free, but contains abundant quartz silt and is dominated by smectite. The 2% difference in porosity does not seem to equate to a significant difference in permeability. Elastic properties derived from wireline log data show that Young&rsquo, s modulus, material stiffness, is very low (5 GPa) for the most shale (clay mineral)-rich Rodby intervals, with Young&rsquo, s modulus increasing as shale content decreases and as cementation (e.g., calcite) increases. Our work has shown that Young&rsquo, s modulus, which can be used to inform the likeliness of tensile failure, may be predictable based on routine gamma, density and compressive sonic logs in the majority of wells where the less common shear logs were not collected. The predictability of Young&rsquo, s modulus from routine well log data could form a valuable element of CCS-site top-seal appraisals. This study has shown that the Rodby and Lista Shales represent good top-seals to the Acorn and East Mey CCS sites and they can hold CO2 column heights of approximately 380 m. The calcite-rich Rodby Shale may be susceptible to localised carbonate dissolution and increasing porosity and permeability but decreasing tendency to develop fracture permeability in the presence of injected CO2, as brittle calcite dissolves. In contrast, the calcite-free, locally quartz-rich, Lista Shale will be geochemically inert to injected CO2 but retain its innate tendency to develop fracture permeability (where quartz rich) in the presence of injected CO2.

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.

This Article contains errors in the Reference list. Reference 3 is incorrectly listed as ‘Song, J. & Zhang, D. Comprehensive Review of Caprock-Sealing Mechanisms for Geologic Carbon Sequestration. 47, 9–22 (2012)’. The correct reference is listed below as ref. 1. Reference 16 is incorrectly listed as ‘Gilfillan, S. M. V. et al. The noble gas geochemistry of natural CO2 gas reservoirs from the Colorado Plateau and Rocky Mountain provinces. USA. 72, 1174–1198 (2008)’. The correct reference is listed below as ref. 2. Reference 20 is incorrectly listed as ‘Alcalde, J. et al. Quantifying geological CO2 storage security to deliver on climate mitigation (2018)’. The correct reference is listed below as ref. 3. Reference 32 is incorrectly listed as ‘Condit, C. D. & Connor, C. B. Recurrence rates of volcanism in basaltic volcanic fields: An example from the Springerville volcanic field. Arizona. 108, 1225–1241 (1996)’. The correct reference is listed below as ref. 4.

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.

Storing CO2 for geological timescales is crucial to delivering decarbonisation of industrial economies aligned with global climate change mitigation objectives. This requires CO2 injection into a large subsurface pore space overlain by a high capillary entry pressure seal rock to prevent CO2 escape. Such formations occur abundantly in productive hydrocarbon basins such as the North Sea. However, these geological conditions for CO2 storage are unavailable close to some large CO2 emitting economic areas in China. We identify this problem and innovate a solution for the example of the Pearl River Mouth Basin (China). This offshore basin has an estimated effective storage capacity of hundreds of Gt CO2 based on reservoir pore volumes. Production and geological data of three oil fields of the Huizhou hydrocarbon cluster are analysed as analogues for large-scale aquifer storage of CO2. Results suggest the injection and storage of CO2 in individual trap structures will perform poorly, due to thin reservoir layers, small structural traps, and indications that the cap rocks may have only limited sealing capability. To address this a novel alternative CO2 sequestration strategy, based on multi reservoir layer injection and dispersion trapping, is recommended to exploit the vast available pore space for CO2 storage.

The Pearl River Mouth Basin aquifer is vast but only small hydrocarbon fields are present in proximal areas. Some of them are not filled to spill which could be due to poor cap rock quality. The sustainable CO2 column heights of the HZ21-1 field were calculated to estimate the CO2 storage capacity. If the lack of large hydrocarbon fields is due to insufficient cap rocks, CO2 storage capacity estimations based on volumetrics for the aquifer will lead to a capacity overestimation. Instead, hydrocarbon fields and additional storage capacity in the overburden due to dispersed trapping should be considered.

Carbon capture and storage (CCS) is proposed as essential in efforts to limit the effects of climate change. CCS is now recognised as “essential, not optional” on the pathway to recover already emitted CO2 and achieve net-negative industrial economies. All aspects of CCS have been established theoretically, experimentally and by pilot trials. The obstacle to deployment is political and economic understanding.

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.

Residual CO2 trapping is a key mechanism of secure CO2 storage, an essential component of the Carbon Capture and Storage technology. Estimating the amount of CO2 that will be residually trapped in a saline aquifer formation remains a significant challenge. Here, we present the first oxygen isotope ratio (δ18O) measurements from a single-well experiment, the CO2CRC Otway 2B Extension, used to estimate levels of residual trapping of CO2. Following the initiation of the drive to residual saturation in the reservoir, reservoir water δ18O decreased, as predicted from the baseline isotope ratios of water and CO2, over a time span of only a few days. The isotope shift in the near-wellbore reservoir water is the result of isotope equilibrium exchange between residual CO2 and water. For the region further away from the well, the isotopic shift in the reservoir water can also be explained by isotopic exchange with mobile CO2 from ahead of the region driven to residual, or continuous isotopic exchange between water and residual CO2 during its back-production, complicating the interpretation of the change in reservoir water δ18O in terms of residual saturation. A small isotopic distinction of the baseline water and CO2 δ18O, together with issues encountered during the field experiment procedure, further prevents the estimation of residual CO2 saturation levels from oxygen isotope changes without significant uncertainty. The similarity of oxygen isotope-based near-wellbore saturation levels and independent estimates based on pulsed neutron logging indicates the potential of using oxygen isotope as an effective inherent tracer for determining residual saturation on a field scale within a few days.

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.

Recent work on analogue CO 2 storage sites has shown that the single most defining natural factor as to whether the store can be successfully utilised to retain 99% of the injected CO 2 for 1000 years is the behaviour of fractures within the low permeability strata acting as caprock. Here we present experimental and numerical investigation of the hydro-mechanical behaviour of a natural fracture in a caprock during the flow of supercritical CO 2 through it. The caprock is a naturally fractured dolomitic limestone sample recovered from a depth of ∼1500 m, and is the primary seal to the natural CO 2 storage analogue, the Fizzy field, in the Southern North Sea. For the first time the hydro mechanical behaviour of the fracture is examined using unique experimental equipment applying multiple high pressure single phase supercritical CO 2 fluid flow experiments at representative in situ reservoir pressures (10–30 MPa, with confining pressures from 35 MPa to 55 MPa) and a temperature of 40 °C. The fracture surfaces are scanned to provide high resolution images both prior to and after the experimental investigation. The results are modelled through the further development of a hybrid numerical analytical approach to fluid flow through a discrete fracture, implemented in the open source code OpenGeoSys. The work indicates that through the statistical approximation of the fracture surface and combination of the application of standard nonlinear flow models and analytical mechanical solutions, the key features of the hydro-mechanical behaviour of the supercritical fluid flow through the sample can be replicated. The results provide insight into erroneous effective stress assumptions at higher fluid pressures and the importance of understanding the coupled process multi-physics behaviour of fractures in a CO 2 storage setting. Over-simplistic approximations using the effective stress law lead to a Biot's coefficient greater than 1 being predicted under varying fluid and confining pressures.

Residual Oil Zones (ROZ) form when oil has leaked or migrated from a reservoir trap through geological time, leaving a zone of immobile oil. Here we assess the feasibility of ROZ production with CO2 flooding, in a North Sea oil field for the first time. We identify a hydrodynamically produced ROZ, with an oil saturation of 26%, in the Pierce Oil Field of the Central North Sea and adapt established recovery factors for Carbon Dioxide Enhanced Oil Recovery (CO2 EOR) from onshore fields, to estimate oil resource and CO2 storage potential. Our mid case results show that CO2 utilisation increases commercial reserves by 5–20% while storing 15 M t CO2. Based on our calculations CO2 EOR can produce low carbon intensity crude oil from a mature basin and could store more CO2 than is released from the production, transport, refining and final combustion of oil.

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.

CCS projects listing and predictions

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.

To ensure the effective long-term storage of CO2 in candidate geological storage sites, evaluation of potential leakage pathways to the surface should be undertaken. Here we use a series of natural CO2 seeps along a fault in South Africa to assess the controls on CO2 leakage to the surface. Geological mapping and detailed photogrammetry reveals extensive fracturing along the mapped fault trace. Measurements of gas flux and CO2 concentration across the fracture corridor give maximum soil gas measurements of 27% CO2 concentration and a flux of 191 g m−2 d−1. These measurements along with observations of gas bubbles in streams and travertine cones attest to CO2 migration to the surface. Permeability measurements on the host rock units show that the tillite should act as an impermeable seal to upward CO2 migration. The combined permeability and fracture mapping data indicate that fracture permeability creates the likely pathway for CO2 migration through the low permeability tillite to the surface. Heterogeneity in fracture connectivity and intensity at a range of scales will create local higher permeability pathways along the fracture corridor, although these may seal with time due to fluid-rock interaction. The results have implications for the assessment and choice of geological CO2 storage sites, particularly in the assessment of sub-seismic fracture networks.

Carbon capture and storage (CCS) can help nations meet their Paris CO2 reduction commitments cost-effectively. However, lack of confidence in geologic CO2 storage security remains a barrier to CCS implementation. Here we present a numerical program that calculates CO2 storage security and leakage to the atmosphere over 10,000 years. This combines quantitative estimates of geological subsurface CO2 retention, and of surface CO2 leakage. We calculate that realistically well-regulated storage in regions with moderate well densities has a 50% probability that leakage remains below 0.0008% per year, with over 98% of the injected CO2 retained in the subsurface over 10,000 years. An unrealistic scenario, where CO2 storage is inadequately regulated, estimates that more than 78% will be retained over 10,000 years. Our modelling results suggest that geological storage of CO2 can be a secure climate change mitigation option, but we note that long-term behaviour of CO2 in the subsurface remains a key uncertainty., Carbon capture and storage can help reduce CO2 emissions but the confidence in geologic CO2 storage security is uncertain. Here the authors present a numerical programme to estimate leakage from wells and find that under appropriate regulation 98% of injected CO2 will be retained over 10,000 years.

The Pentland Formation of the UK Central North Sea is a quartzite in a sequence of more arkosic sandstones. Provenance-sensitive heavy mineral indices are interpreted to indicate that it was probably derived by erosion of arkosic sediments, which also supplied the arkosic marine sandstones of the contemporaneous Fulmar Formation. A lack of apatite within the Pentland Formation suggests that the feldspars could have dissolved during exposure to groundwaters during very shallow burial. However, petrographic and geochemical evidence supports survival of at least some of the feldspar to burial depths in excess of at least 2 km, when the sandstones had been stabilized against compaction by quartz cements or overpressure. Abundant kaolin, which has not reacted to form illite, is preserved at burial depths in excess of 4000 m, suggesting an unusual lack of available potassium. There is a strong contrast in diagenetic pathways with the overlying marine Fulmar Formation, which most probably had the same initial composition but in which kaolin is absent and fibrous illite is present. It is suggested that a lower concentration of potassium (and aluminium) within the Pentland Formation compared with the probable source and the comparably sourced Fulmar Formation represents export of K from the sands on a metre scale.

To prevent ocean acidification and mitigate greenhouse gas emissions, it is necessary to capture and store carbon dioxide. The Sleipner storage site, offshore Norway, is the world's first and largest engineered waste repository for a greenhouse gas. CO2 is separated from the Sleipner gas condensate field and stored in the pore space of the Utsira Formation, a saline aquifer approximately 1 km below the surface and 200 km from the coast. Statoil, the field operator, has injected almost 1 Mt/yr of captured CO2 into the storage site since 1996. The buoyant CO2 plume ascended rapidly through eight thin shale barriers within the aquifer to reach the top seal in less than three years. The plume's progress has been monitored by eight seismic surveys, as well as gravimetric and electromagnetic monitoring, which record the spreading of nine thin CO2 layers. This paper presents a capillary flow model using invasion percolation physics that accurately matches the plume's geometry. The approach differs from standard Darcy flow simulations, which fail to match the plume geometry. The calibrated capillary flow simulation indicates that a mass balance for the plume is likely, but can only replicate the plume geometry if the thin intra-formational shale barriers are fractured. The model enables an estimate of the shale barrier behavior and caprock performance. The fractures are very unlikely to have been caused by CO2 injection given the confining stress of the rock and weak overpressure of the plume, and so fracturing must pre-date injection. A novel mechanism is suggested: the deglaciation of regional ice sheets that have rapidly and repeatedly unloaded approximately 1 km of ice. The induced transient pore pressures are sufficient to hydro-fracture thin shales. The fractures enable fast CO2 ascent, resulting in a multi-layered plume. Shallow CO2 storage sites in the Northern North Sea and other regions that have been loaded by Quaternary ice sheets are likely to behave in a similar manner.

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.

The aggregate technical potential for land-based negative emissions technologies (NETs) in the UK is estimated to be 12-49 Mt C eq. per year, representing around 8-32% of current emissions. The proportion of this potential that could be realized is limited by a number of cost, energy and environmental constraints which vary greatly between NETs.

Inherent tracers-the "natural" isotopic and trace gas composition of captured CO2 streams-are potentially powerful tracers for use in CCS technology. This review outlines for the first time the expected carbon isotope and noble gas compositions of captured CO2 streams from a range of feedstocks, CO2-generating processes, and carbon capture techniques. The C-isotope composition of captured CO2 will be most strongly controlled by the feedstock, but significant isotope fractionation is possible during capture; noble gas concentrations will be controlled by the capture technique employed. Comparison with likely baseline data suggests that CO2 generated from fossil fuel feedstocks will often have δ(13)C distinguishable from storage reservoir CO2. Noble gases in amine-captured CO2 streams are likely to be low concentration, with isotopic ratios dependent on the feedstock, but CO2 captured from oxyfuel plants may be strongly enriched in Kr and Xe which are potentially valuable subsurface tracers. CO2 streams derived from fossil fuels will have noble gas isotope ratios reflecting a radiogenic component that will be difficult to distinguish in the storage reservoir, but inheritance of radiogenic components will provide an easily recognizable signature in the case of any unplanned migration into shallow aquifers or to the surface.

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.

Anthropogenic energy-related CO2 emissions are higher than ever. With new fossil-fuel power plants, growing energy-intensive industries and new sources of fossil fuels in development, further emissions increase seems inevitable. The rapid application of carbon capture and storage is a much heralded means to tackle emissions from both existing and future sources. However, despite extensive and successful research and development, progress in deploying carbon capture and storage has stalled. No fossil-fuel power plants, the greatest source of CO2 emissions, are using carbon capture and storage, and publicly supported demonstration programmes are struggling to deliver actual projects. Yet, carbon capture and storage remains a core component of national and global emissions-reduction scenarios. Governments have to either increase commitment to carbon capture and storage through much more active market support and emissions regulation, or accept its failure and recognize that continued expansion of power generation from burning fossil fuels is a severe threat to attaining objectives in mitigating climate change.

Capture and geological storage of CO2 is emerging as an attractive means of economically abating anthropogenic CO2 emissions from point sources. However, for the technology to be widely deployed it is essential that a reliable means to assess a site for both storage performance and regulation compliance exists. Hence, the ability to identify the origin of any CO2 seepage measured at the near-surface and ground surface and determine if it originates from a deep storage site or a different source is critical. As an analogue for post-emplacement seepage, here we examine natural CO2 rich springs and groundwater wells in the vicinity of the St. Johns Dome CO2 reservoir located on the border of Mid-Arizona/New Mexico, USA. Extensive travertine deposits in the region document a long history of migration of CO2 rich fluids to the surface. The presence of CO2 rich fluids today are indicated by high levels of HCO3- in surface spring and groundwater well waters. We document measurements of dissolved noble gases and carbon isotopes from these springs and wells. We show that a component of the He fingerprint measured in gaseous CO2 sampled in the deep reservoir, can be traced along a fault plane to occur in waters from both groundwater wells and the majority of springs emerging at the surface above the reservoir. Our results show for the first time that CO2 can be fingerprinted from source to surface using noble gases and illustrates that this technique could be used to identify dissolved CO2 migration from engineered storage sites. (C) 2011 Elsevier Ltd. All rights reserved.

Exceptionally high-porosity sandstones are reported from oil provinces worldwide, yet the mechanism of porosity preservation remains controversial. We present strong evidence that the exceptional porosities in the Jurassic Fulmar Formation within the North Sea are the result of early oil charging preventing cementation and chemical compaction in sands with relatively low detrital clay contents, although overpressure and grain coatings do have some effect. The most dramatic evidence that reservoir quality is related to early oil charge is the spatial distribution of the porosity: the maximum porosity of the Fulmar Formation is systematically highest immediately below the top seal, and decreases below this despite uniform sedimentology. Hence, porosity is preferentially preserved where oil first accumulated in these unusually homogeneous overpressured reservoir sandstones, at the top. Oil charge prevents or significantly retards chemical compaction and cementation of a reservoir, preserving porosity. There is independent evidence for early oil charging of reservoirs within the Central Graben, from fluid inclusion studies and K–Ar age dates of authigenic illite. Micro-quartz grain coatings, which have been proposed to preserve porosity during burial, are associated with only 5% extra porosity in sands that exceed the worldwide average sandstone porosity by almost 20%.

Miller field of the North Sea has had high concentrations of natural CO2 for ~70 Ma. It is an ideal analog for the long-term fate of CO2 during engineered storage, particularly for formation of carbonate minerals that permanently lock up CO2 in solid form. The Brae Formation reservoir sandstone contains an unusually high quantity of calcite concretions; however, C and O stable isotopic signatures suggest that these are not related to the present-day CO2 charge. Margins of the concretions are corroded, probably because of reduced pH due to CO2 influx. Dispersed calcite cements are also present, some of which postdate the CO2 charge and, therefore, are the products of mineral trapping. It is calculated that only a minority of the reservoired CO2 in Miller (6–24%) has been sequestrated in carbonates, even after 70 Ma of CO2 emplacement. Most of the CO2 accumulation is dissolved in pore fluids. Therefore, in a reservoir similar to the Brae Formation, engineered CO2 storage must rely on physical retention mechanisms because mineral trapping is both incomplete and slow.

The capture of carbon dioxide at the point of emission from coal- or gas-burning power plants is an attractive route to reducing carbon dioxide emissions into the atmosphere. To commercialize carbon capture, as well as transport of liquified carbon dioxide and its storage in exploited oil fields or saline formations, many technological, commercial, and political hurdles remain to be overcome. Urgent action is required if carbon capture and storage is to play a large role in limiting climate change.

Geochemical models of CO2 injection into reservoir sandstones often predict the growth of minerals that will permanently store the CO2 in solid form, and injection experiments record significant fluctuations in porewater chemistry on a short time scale. Yet the proportion of CO2 reaction may be small, even over geological time scales. A southern North Sea (UK) gas accumulation with a high natural CO2 content (c. 50%) forms a natural analogue to engineered storage, and provides a calibration point for geochemical models of CO2–rock reaction. In the analogue site, the carbonate mineral dawsonite has formed in only trace amounts (0.4 ± 0.3% solid volume) despite exposure to high levels of CO2 for 50 Myr or more. It is calculated that only 2.4 (± 0.9)% of the CO2 present within the structure is currently locked up as dawsonite, and a similar quantity in solution in the porewaters. Comparison of stable O and C isotopes with a neighboring field with low CO2 content gas suggests that up to 0.7 (± 2)% solid volume dolomite cement is associated with the CO2 charge, equivalent to 0–25% of the total CO2. The remaining 70–95% of the CO2 is present as a free phase, after tens of millions of years. Consequently, geological storage of anthropogenic CO2 in reservoirs similar to the Rotliegend Group must rely on physical containment and not mineral sequestration. The Rotliegend Group is still an excellent candidate for a CO2 storage reservoir, though using physical trapping mechanisms and not chemical ones.