Corrective measures based on pressure control strategies for CO2 geological storage in deep aquifers

A prerequisite to the wide deployment at an industrial scale of CO₂ geological storage is demonstrating that potential risks can be efficiently managed. Corrective measures in case of significant irregularities, such as CO₂ leakage, are hence required as advocated by the recent European directive on Carbon Capture and Storage operations. In this regard, the objective of the present paper is to investigate four different corrective measures aiming at controlling the overpressure induced by the injection operations in the reservoir: stopping the CO₂ injection and relying on the natural pressure recovery in the reservoir; extracting the stored CO₂ at the injection well; extracting brine at a distant well while stopping the CO₂ injection, and extracting at a distant well without stopping the CO₂ injection. The efficiency of the measures is assessed using multi-phase fluid flow numerical simulations. The application case is the deep carbonate aquifer of the Dogger geological unit in the Paris Basin. A comparative study between the four corrective measures is then carried using a cost-benefit approach. Results show that an efficient overpressure reduction can be achieved by simply shutting-in the well. The overpressure reduction can be significantly accelerated by means of fluid extraction but the adverse consequences are the associated higher costs of the intervention operations.     

A response surface methodology to address uncertainties in cap rock failure assessment for CO2 geological storage in deep aquifers

Cap rock failure assessment, either tensile fracturing or shear slip reactivation of pre-existing fault, is a key issue for preventing CO₂ leakage from deep aquifer reservoirs up to the surface. For an appropriate use in risk management, the uncertainties associated with such studies should be investigated. Nevertheless, uncertainty analysis requires multiple simulations and a direct use of conventional numerical approaches might be too computer time consuming. An alternative is to use conventional analytical models, but their assumptions appear to be too conservative. An intermediate approach is then proposed based on the response surface methodology, consisting in estimating the effective stress state after CO₂ injection as a linear combination of the most influential site properties based on a limited number of numerical simulations. The decision maker is provided with three levels of information: (1) the identification of the most important site properties; (2) an analytical model for a quick assessment of the maximal sustainable overpressure and (3) a simplified model to be used in a computationally intensive uncertainty analysis framework. This generic methodology is illustrated with the Paris Basin case using a large-scale hydromechanical model to assess cap rock failure in the injector zone.     

Investigations on CO2 storage capacity in saline aquifers: Part 1. Dimensional analysis of flow processes and reservoir characteristics

The CO₂ storage capacity of geological reservoirs is of great interest for the selection of potential storage sites in carbon capture and storage (CCS) projects. A detailed analysis essentially requires a thorough understanding of the interaction of forces acting within the system. By defining characteristic quantities for length, time, pressure and velocity, the governing multiphase flow equations can be non-dimensionalised. This allows for the definition of physically sound dimensionless numbers, resembling the ratios of acting forces like viscous, capillary and gravitational forces. An analysis of the relation of forces in reservoirs with different parameter setups allows their intercomparison with respect to their CO₂ storage capacity potential. To back up the analysis, a comprehensive reservoir parameter database with more than 1200 reservoirs is analysed and statistical characteristics are derived. Effects of reservoir parameters like depth, temperature, absolute and relative permeability, as well as capillary pressure are investigated. It is shown that dimensionless numbers can be used to qualitatively order reservoirs with respect to the forces acting in the reservoir. Moreover, it is shown that the relative permeability relations together with the residual saturations have a great influence on the balance of forces.     

Coupled hydromechanical modeling of CO2 sequestration in deep saline aquifers

Sequestration of carbon dioxide (CO₂) in deep saline aquifers has emerged as an option for reducing greenhouse gas emissions to the atmosphere. The large amounts of supercritical CO₂ that need to be injected into deep saline aquifers may cause large fluid pressure increases. The resulting overpressure may promote reactivation of sealed fractures or the creation of new ones in the caprock seal. This could lead to escape routes for CO₂. In order to assess the probability of such an event, we model an axisymmetric horizontal aquifer–caprock system, including hydromechanical coupling. We study the failure mechanisms, using a viscoplastic approach. Simulations illustrate that, depending on boundary conditions, the least favorable moment takes place at the beginning of injection. Initially, fluid pressure rises sharply because of a reduction in permeability due to desaturation. Once CO₂ fills the pores in the vicinity of the injection well and a capillary fringe is fully developed, the less viscous CO₂ displaces the brine and the capillary fringe laterally. The overpressure caused by the permeability reduction within the capillary fringe due to desaturation decreases with distance from the injection well. This results in a drop in fluid pressure buildup with time, which leads to a safer situation. Nevertheless, in the presence of low-permeability boundaries, fluid pressure continues to rise in the whole aquifer. This occurs when the radius of influence of the injection reaches the outer boundary. Thus, caprock integrity might be compromised in the long term.     

Long-term variations of CO2 trapped in different mechanisms in deep saline formations: A case study of the Songliao Basin,China

The geological storage of CO₂ in deep saline formations is increasing seen as a viable strategy to reduce the release of greenhouse gases to the atmosphere. There are numerous sedimentary basins in China, in which a number of suitable CO₂ geologic reservoirs are potentially available. To identify the multi-phase processes, geochemical changes and mineral alteration, and CO₂ trapping mechanisms after CO₂ injection, reactive geochemical transport simulations using a simple 2D model were performed. Mineralogical composition and water chemistry from a deep saline formation of Songliao Basin were used. Results indicate that different storage forms of CO₂ vary with time. In the CO₂ injection period, a large amount of CO₂ remains as a free supercritical phase (gas trapping), and the amount dissolved in the formation water (solubility trapping) gradually increases. Later, gas trapping decrease, solubility trapping increases significantly due to the migration and diffusion of CO₂ plume and the convective mixing between CO₂-saturated water and unsaturated water, and the amount trapped by carbonate minerals increases gradually with time. The residual CO₂ gas keeps dissolving into groundwater and precipitating carbonate minerals. For the Songliao Basin sandstone, variations in the reaction rate and abundance of chlorite, and plagioclase composition affect significantly the estimates of mineral alteration and CO₂ storage in different trapping mechanisms. The effect of vertical permeability and residual gas saturation on the overall storage is smaller compared to the geochemical factors. However, they can affect the spatial distribution of the injected CO₂ in the formations. The CO₂ mineral trapping capacity could be in the order of 10 kg/m³ medium for the Songliao Basin sandstone, and may be higher depending on the composition of primary aluminosilicate minerals especially the content of Ca, Mg, and Fe.     

Experimental study on CO2 monitoring and quantification of stored CO2 in saline formations using resistivity measurements

This paper reports CO₂ saturation estimations based on resistivity data obtained from laboratory measurements and induction logging results at the Nagaoka pilot CO₂ injection site. The laboratory experiments put in evidence that the presence of clay content tends to reduce the increase of resistivity caused by the displacement of brine by less conductive CO₂. As a result, CO₂ saturations estimated from resistivity measurements without any correction for the clay effect are considerably lower than the actual saturations. The resistivity index (RI) provides better estimates of CO₂ saturations than the Archie's equation because it requires the determination or assumption of only one rock parameter: the saturation exponent. CO₂ saturations estimated from the induction logging data acquired at Nagaoka are considerably lower than the neutron porosity changes due to displacement between brine and CO₂ in the reservoir. Even in the case of considering the De Witte's equation and the Poupon's to account for the clay effect, it was still difficult to get a good agreement with the neutron logging results. New relations based on the resistivity index with correction factors for the clay effect are developed and implemented in this study. One of these relations has proved to be effective to estimate CO₂ saturations in saline formations with high clay content.     

Monitoring of the microbial community composition in saline aquifers during CO2 storage by fluorescence in situ hybridisation

This study reveals the first analyses of the composition and activity of the microbial community of a saline CO₂ storage aquifer. Microbial monitoring during CO₂ injection has been reported. By using fluorescence in situ hybridisation (FISH), we have shown that the microbial community was strongly influenced by the CO₂ injection. Before CO₂ arrival, up to 6 × 10⁶ cells ml⁻¹ were detected by DAPI staining at a depth of 647 m below the surface. The microbial community was dominated by the domain Bacteria that represented approximately 60% to 90% of the total cell number, with Proteobacteria and Firmicutes as the most abundant phyla comprising up to 47% and 45% of the entire population, respectively. Both the total cell counts as well as the counts of the specific physiological groups revealed quantitative and qualitative changes after CO₂ arrival. Our study revealed temporal outcompetition of sulphate-reducing bacteria by methanogenic archaea. In addition, an enhanced activity of the microbial population after five months CO₂ storage indicated that the bacterial community was able to adapt to the extreme conditions of the deep biosphere and to the extreme changes of these atypical conditions.     

CO2 capture from coal-fired power plants based on sodium carbonate slurry; a systems feasibility and sensitivity study

In this work the feasibility of a CO₂ capture system based on sodium carbonate–bicarbonate slurry and its integration with a power plant is studied. The results are compared to monoethanolamine (MEA)-based capture systems. Condensing power plant and combined heat and power plant with CO₂ capture is modelled to study the feasibility of combined heat and power plant for CO₂ capture.Environmental friendly sodium carbonate would be an interesting chemical for CO₂ capture. Sodium carbonate absorbs CO₂ forming sodium bicarbonate. The low solubility of sodium bicarbonate is a weak point for the sodium carbonate based liquid systems since it limits the total concentration of carbonate. In this study the formation of solid bicarbonate is allowed, thus forming slurry, which can increase the capacity of the solvent. With this the energy requirement of stripping of the solvent could potentially be around 3.22 MJ/kg of captured CO₂ which is significantly lower than with MEA based systems which typically have energy consumption around 3.8 MJ/kg of captured CO₂.Combined heat and power plants seem to be attractive for CO₂ capture because of the high total energy efficiency of the plants. In a condensing power plant the CO₂ capture decreases directly the electricity production whereas in a combined heat and power plant the loss can be divided between district heat and electricity according to demand.     

Pathways towards large-scale implementation of CO2 capture and storage: A case study for the Netherlands

We sketch four possible pathways how carbon dioxide capture and storage (CCS) (r)evolution may occur in the Netherlands, after which the implications in terms of CO₂ stored and avoided, costs and infrastructural requirements are quantified. CCS may play a significant role in decarbonising the Dutch energy and industrial sector, which currently emits nearly 100 Mt CO₂/year. We found that 15 Mt CO₂ could be avoided annually by 2020, provided some of the larger gas fields that become available the coming decade could be used for CO₂ storage. Halfway this century, the mitigation potential of CCS in the power sector, industry and transport fuel production is estimated at maximally 80–110 Mt CO₂/year, of which 60–80 Mt CO₂/year may be avoided at costs between 15 and 40 €/t CO₂, including transport and storage. Avoiding 30–60 Mt CO₂/year by means of CCS is considered realistic given the storage potential represented by Dutch gas fields, although it requires planning to assure that domestic storage capacity could be used for CO₂ storage. In an aggressive climate policy, avoiding another 50 Mt CO₂/year may be possible provided that nearly all capture opportunities that occur are taken. Storing such large amounts of CO₂ would only be possible if the Groningen gas field or large reservoirs in the British or Norwegian part of the North Sea will become available.     

Evaluating the impact of fractures on the performance of the In Salah CO2 storage site

The In Salah Gas Joint Venture CO₂ storage project has been in operation in Algeria since 2004 and is currently the world's largest onshore CO₂ storage project. CO₂ is injected into the saline aquifer of a gas reservoir several kilometres away from the gas producers. Current focus in the project is on implementing a comprehensive monitoring strategy and modelling the injection behaviour in order to ensure and verify safe long-term storage. A key part of this effort is the understanding of the processes involved in CO₂ migration within relatively low-permeability sandstones and shales influenced by fractures and faults. We summarise our current understanding of the fault and fracture pattern at this site and show preliminary forecasts of the system performance using discrete fracture models and fluid flow simulations. Despite evidence of fractures at the reservoir/aquifer level, the thick mudstone caprock sequence is expected to provide an effective flow and mechanical seal for the storage system; however, quantification of the effects of fracture flow is essential to the site verification.     

Chromatographic partitioning of impurities (H2S) contained in a CO2 stream injected into a deep saline aquifer: Part 2. Effects of flow conditions

Laboratory experiments reported in a companion paper were carried out to examine the chromatographic partitioning of impurities contained in a stream of CO₂ injected into a deep saline aquifer. The solubility of the impurity gas in the CO₂ stream compared to that of CO₂, the in situ conditions of pressure, temperature and water salinity, and the concentration of the impurity gas affect the partitioning of the two gases. For CO₂ streams containing H₂S, numerical simulations reported here have successfully replicated the laboratory results including the breakthrough of CO₂ ahead of H₂S. Sensitivity analysis performed with the numerical model has shown that flow conditions, controlled by such parameters as medium permeability, pressure gradient, dispersion, gas mobility and flow direction, affect the breakthrough time and separation of the two gases, leading to delayed or earlier breakthrough, and increasing or decreasing the time lag between the breakthrough of the two gases. Vertical bottom-up flow leads to earlier breakthrough, while top-down flow leads to delayed breakthrough. These results are important in establishing monitoring strategies at CO₂ storage sites and in evaluating the risks associated with the possible leakage of injected CO₂ that contains impurities.     

Integration of counter-current relative permeability in the simulation of CO2 injection into saline aquifers

Carbon dioxide (CO₂) injection into saline aquifers is one of the promising options to sequester large amounts of CO₂ in geological formations. During as well as after injection of CO₂ into an aquifer, CO₂ migrates towards the top of the formation due to density differences between the formation brine and the injected CO₂. The time scales of CO₂ migration towards the top of an aquifer and the fraction of CO₂ that is trapped as residual gas depends strongly on the driving forces that are acting on the injected CO₂.When CO₂ migrates to the top of an aquifer, brine may be displaced downwards in a counter-current flow setting particularly during the injection period. A majority of the published work on counter-current flow settings have reported significant reductions in the associated relative permeability functions as compared to co-current measurements. However, this phenomenon has not yet been considered in the simulation of CO₂ storage into saline aquifers.In this paper we study the impact of changes in mobility for the two-phase brine/CO₂ system as a result of transitions between co- and counter-current flow settings. We have included this effect in a simulator and studied the impact of the related mobility reduction on the saturation distribution and residual saturation of CO₂ in aquifers over relevant time scales. We demonstrate that the reduction in relative permeability in the vertical direction changes the plume migration pattern and has an impact on the amount of gas that is trapped as a function of time. This is to our best knowledge the first attempt to integrate counter-current relative permeability into the simulation of injection and subsequent migration of CO₂ in aquifers. The results and analysis presented in this paper are directly relevant to all ongoing activities related to the design of large-scale CO₂ storage in saline aquifers.     

CO2 storage capacity estimation: Issues and development of standards

Associated with the endeavours of geoscientists to pursue the promise that geological storage of CO₂ has of potentially making deep cuts into greenhouse gas emissions, Governments around the world are dependent on reliable estimates of CO₂ storage capacity and insightful indications of the viability of geological storage in their respective jurisdictions. Similarly, industry needs reliable estimates for business decisions regarding site selection and development. If such estimates are unreliable, and decisions are made based on poor advice, then valuable resources and time could be wasted. Policies that have been put in place to address CO₂ emissions could be jeopardised. Estimates need to clearly state the limitations that existed (data, time, knowledge) at the time of making the assessment and indicate the purpose and future use to which the estimates should be applied. A set of guidelines for estimation of storage capacity will greatly assist future deliberations by government and industry on the appropriateness of geological storage of CO₂ in different geological settings and political jurisdictions. This work has been initiated under the auspices of the Carbon Sequestration Leadership Forum (www.cslforum.org), and it is intended that it will be an ongoing taskforce to further examine issues associated with storage capacity estimation.     

Preliminary assessment of CO2 geological storage opportunities in Greece

This paper provides a preliminary assessment of the suitability of Tertiary sedimentary basins in Northern, Western and Eastern Greece in order to identify geological structures close to major CO₂ emission sources with the potential for long-term storage of CO₂. The term “emissions” refers to point source emissions as defined by the International Energy Agency, including power generation, the cement sector and other industrial processes. The Prinos oil field and saline aquifer, along with the saline formations of the Thessaloniki Basin and the Mesohellenic Trough have been identified as prospective CO₂ geological storage sites. In addition, a carbonate deep saline aquifer occurring at appropriate depths beneath the Neogene-Quaternary sediments of Ptolemais-Kozani graben (NW Greece) is considered. The proximity of this geological formation to Greece's largest lignite-fired power plants suggests that it would be worthwhile undertaking further site-specific studies to quantify its storage capacity and assess its structural integrity.     

Chromatographic partitioning of impurities contained in a CO2 stream injected into a deep saline aquifer: Part 1. Effects of gas composition and in situ conditions

A series of laboratory experiments were carried out to examine the chromatographic partitioning of impurities contained in a stream of CO₂ injected into a deep saline aquifer. The experiments were carried out under static (no flow) and dynamic conditions, mainly with H₂S as the impurity in the CO₂ stream, for 2%, 5% and 30% concentrations, and for in situ conditions of high pressure, temperature and water salinity, and also for pure water at a lower pressure and temperature. In addition, experiments were conducted using CH₄, N₂ and SO₂ at 5% concentration as the ‘Impurity’ in the CO₂ stream. The experiments show that gases in an impure stream of CO₂ being injected into a deep saline aquifer will chromatographically partition at the leading edge of the gas advancing through the water-saturated porous medium as a result of differential solubility in aquifer water. The solubility of the impurity gas in the CO₂ stream compared to that of CO₂ is the most dominant factor in regard to the breakthrough time and initial gas concentrations in the effluent. The in situ conditions of pressure, temperature and water salinity also affect the chromatographic partitioning of CO₂ and impurities contained in the injection stream through their general effect on the solubility of all gases. The concentration of the impurity gas in the feed gas stream has a secondary effect on the breakthrough and time lag decreasing with increasing concentration of the impurity gas. These experimental findings are significant for understanding the fate of the injected CO₂ and associated impurities contained in an injection stream, in devising monitoring procedures and protocols, and in developing emergency response plans in case of leakage of CO₂ and associated impurities.     

Basin-scale hydrogeologic impacts of CO2 storage: Capacity and regulatory implications

Industrial-scale injection of CO₂ into saline formations in sedimentary basins will cause large-scale fluid pressurization and migration of native brines, which may affect valuable groundwater resources overlying the deep sequestration aquifers. In this paper, we discuss how such basin-scale hydrogeologic impacts (1) may reduce current storage capacity estimates, and (2) can affect regulation of CO₂ storage projects. Our assessment arises from a hypothetical future carbon sequestration scenario in the Illinois Basin, which involves twenty individual CO₂ storage projects (sites) in a core injection area most suitable for long-term storage. Each project is assumed to inject five million tonnes of CO₂ per year for 50 years. A regional-scale three-dimensional simulation model was developed for the Illinois Basin that captures both the local-scale CO₂–brine flow processes and the large-scale groundwater flow patterns in response to CO₂ storage. The far-field pressure buildup predicted for this selected sequestration scenario support recent studies in that environmental concerns related to near- and far-field pressure buildup may be a limiting factor on CO₂ storage capacity. In other words, estimates of storage capacity, if solely based on the effective pore volume available for safe trapping of CO₂, may have to be revised based on assessments of pressure perturbations and their potential impacts on caprock integrity and groundwater resources. Our results suggest that (1) the area that needs to be characterized in a permitting process may comprise a very large region within the basin if reservoir pressurization is considered, and (2) permits cannot be granted on a single-site basis alone because the near- and far-field hydrogeologic response may be affected by interference between individual storage sites. We also discuss some of the challenges in making reliable predictions of large-scale hydrogeologic impacts related to CO₂ sequestration projects.     

Assessing the economic feasibility of regional deep saline aquifer CO2 injection and storage: A geomechanics-based workflow applied to the Rose Run sandstone in Eastern Ohio, USA

Typical top-down regional assessments of CO₂ storage feasibility are sufficient for determining the maximum volumetric capacity of deep saline aquifers. However, they do not reflect the regional economic feasibility of storage. This is controlled, in part, by the number and type of injection wells that are necessary to achieve regional CO₂ storage goals. In contrast, the geomechanics-based assessment workflow that we present in this paper follows a bottom-up approach for evaluating regional deep saline aquifer CO₂ storage feasibility. The CO₂ storage capacity of an aquifer is a function of its porous volume as well as its CO₂ injectivity. For a saline aquifer to be considered feasible in this assessment it must be able to store a specified amount of CO₂ at a reasonable cost per ton of CO₂. The proposed assessment workflow has seven steps that include (1) defining the storage project and goals, (2) characterizing the geology and developing a geomechanical model of the aquifer, (3) constructing 3D aquifer models, (4) simulating CO₂ injection, (5,6) evaluating CO₂ injection and storage feasibility (with and without injection well stimulation), and (7) determining whether it is economically feasible to proceed with the storage project. The workflow was applied to a case study of the Rose Run sandstone aquifer in the Eastern Ohio River Valley, USA. We found that it is feasible in this region to inject 113 Mt CO₂/year for 30 years at an associated well cost of less than US $1.31/t CO₂, but only if injectivity enhancement techniques such as hydraulic fracturing and injection induced micro-seismicity are implemented.     

Electricity systems with near-zero emissions of CO2 based on wind energy and coal gasification with CCS and hydrogen storage

Emissions from electricity generation will have to be reduced to near-zero to meet targets for reducing overall greenhouse gas emissions. Variable renewable energy sources such as wind will help to achieve this goal but they will have to be used in conjunction with other flexible power plants with low-CO₂ emissions. A process which would be well suited to this role would be coal gasification hydrogen production with CCS, underground buffer storage of hydrogen and independent gas turbine power generation. The gasification hydrogen production and CO₂ capture and storage equipment could operate at full load and only the power plants would need to operate flexibly and at low load, which would result in substantial practical and economic advantages. This paper analyses the performances and costs of such plants in scenarios with various amounts of wind generation, based on data for power demand and wind energy variability in the UK. In a scenario with 35% wind generation, overall emissions of CO₂ could be reduced by 98–99%. The cost of abating CO₂ emissions from the non-wind residual generation using the technique proposed in this paper would be less than 40% of the cost of using coal-fired power plants with integrated CCS.     

Storage of CO2 in saline aquifers: Effects of gravity, viscous, and capillary forces on amount and timing of trapping

CO₂ can be effectively immobilized during CO₂ injection into saline aquifers by residual trapping – also known as capillary trapping – a process resulting from capillary snap-off of isolated CO₂ bubbles. Simulations of CO₂ injection were performed to investigate the interplay of viscous and gravity forces and capillary trapping of CO₂. Results of those simulations show that gas injection processes in which gravitational forces are weak compared to viscous forces (low gravity number N_gv) trap significantly more CO₂ than do flows with strong gravitational forces relative to the viscous forces (high N_gv). The results also indicate that over a wide range of gravity numbers (N_gv), significant fractions of the trapping of CO₂ can occur relatively quickly. The amount of CO₂ that is trapped after injection ceases is demonstrated to correlate with N_gv. For some simulated displacements, effects of capillary pressure and aquifer dip angle on the amount and the rate of trapping are reported. Trapping increases when effects of capillary pressure and aquifer inclination are included in the model. Finally we show that injection schemes such as alternating injection of brine and CO₂ or brine injection after CO₂ injection can also enhance the trapping behavior.     

Large-scale utilization of biomass energy and carbon dioxide capture and storage in the transport and electricity sectors under stringent CO2 concentration limit scenarios

Large-scale, dedicated commercial biomass energy systems are a potentially large contributor to meeting global climate policy targets by the end of the century. We use an integrated assessment model of energy and agriculture systems to show that, given a climate policy in which terrestrial carbon is appropriately valued equally with carbon emitted from the energy system, biomass energy has the potential to be a major component of achieving these low concentration targets. A key aspect of the research presented here is that the costs of processing and transporting biomass energy at much larger scales than current experience are explicitly incorporated into the modeling. From the scenario results, 120–160 EJ/year of biomass energy is produced globally by midcentury and 200–250 EJ/year by the end of this century. In the first half of the century, much of this biomass is from agricultural and forest residues, but after 2050 dedicated cellulosic biomass crops become the majority source, along with growing utilization of waste-to-energy. The ability to draw on a diverse set of biomass-based feedstocks helps to reduce the pressure for drastic large-scale changes in land use and the attendant environmental, ecological, and economic consequences those changes would unleash. In terms of the conversion of bioenergy feedstocks into value added energy, this paper demonstrates that biomass is and will continue to be used to generate electricity as well as liquid transportation fuels. A particular focus of this paper is to show how climate policies and technology assumptions – especially the availability of carbon dioxide capture and storage (CCS) technologies – affect the decisions made about where the biomass is used in the energy system. The potential for net-negative electric sector emissions through the use of CCS with biomass feedstocks provides an attractive part of the solution for meeting stringent emissions constraints; we find that at carbon prices above $150/tCO₂, over 90% of biomass in the energy system is used in combination with CCS. Despite the higher technology costs of CCS, it is a very important tool in controlling the cost of meeting a target, offsetting the venting of CO₂ from sectors of the energy system that may be more expensive to mitigate, such as oil use in transportation. CCS is also used heavily with other fuels such as coal and natural gas, and by 2095 a total of 1530 GtCO₂ has been stored in deep geologic reservoirs. The paper also discusses the role of cellulosic ethanol and Fischer–Tropsch biomass derived transportation fuels as two representative conversion processes and shows that both technologies may be important contributors to liquid fuels production, with unique costs and emissions characteristics.