Prospects for cost-effective post-combustion CO2 capture from industrial CHPs

Industrial Combined Heat and Power plants (CHPs) are often operated at partial load conditions. If CO₂ is captured from a CHP, additional energy requirements can be fully or partly met by increasing the load. Load increase improves plant efficiency and, consequently, part of the additional energy consumption would be offset. If this advantage is large enough, industrial CHPs may become an attractive option for CO₂ capture and storage CCS. We therefore investigated the techno-economic performance of post-combustion CO₂ capture from small-to-medium-scale (50–200 MWe maximum electrical capacity) industrial Natural Gas Combined Cycle- (NGCC-) CHPs in comparison with large-scale (400 MWe) NGCCs in the short term (2010) and the mid-term future (2020–2025). The analyzed system encompasses NGCC, CO₂ capture, compression, and branch CO₂ pipeline.The technical results showed that CO₂ capture energy requirement for industrial NGCC-CHPs is significantly lower than that for 400 MWe NGCCs: up to 16% in the short term and up to 12% in the mid-term future. The economic results showed that at low heat-to-power ratio operations, CO₂ capture from industrial NGCC-CHPs at 100 MWe in the short term (41–44 €/tCO₂ avoided) and 200 MWe in the mid-term future (33–36 €/tCO₂ avoided) may compete with 400 MWe NGCCs (46–50 €/tCO₂ avoided short term, 30–35 €/tCO₂ avoided mid-term).     

Integration and evaluation of a power plant with a CaO-based CO2 capture system

This paper explores the integration and evaluation of a power plant with a CaO-based CO₂ capture system. There is a great amount of recoverable heat in the CaO-based CO₂ capture process. Five cases for the possible integration of a 600 MW power plant with CaO-based CO₂ capture process are considered in this paper. When the system is configured so that recovered heat is used to replace part of the boiler heat load (Case 2), modelling not only shows that this is the system recovering the most heat of 1008.8 MW but also results in the system with the lowest net power output of 446 MW and the second lowest of efficiency of 34.1%. It is indicated that system performance depends both on the amount of heat recovery and the type of heat utilization. When the system is configured so that a 400 MW power plant is built using the recovered heat (Case 4), modelling shows that this is the system with the most net power output of 846 MW, the highest efficiency of 36.8%, the lowest cost of electricity of 54.3 €/MWh and the lowest cost of CO₂ avoided of 28.9 €/tCO₂. This new built steam cycle will not affect the operation of the reference plant which vents its CO₂ to the atmosphere, highly reducing the connection between the CO₂ capture process and the reference plant which vents its CO₂ to the atmosphere. The average cost of electricity and the cost of CO₂ avoided of the five cases are about 58.9 €/kWh and 35.9 €/tCO₂, respectively.     

Methodology for CO2 chain analysis

The paper presents a methodology for CO₂ chain analysis with particular focus on the impact of technology development on the total system economy. The methodology includes the whole CO₂ chain; CO₂ source, CO₂ capture, transport and storage in aquifers or in oil reservoirs for enhanced oil recovery. It aims at supporting the identification of feasible solutions and assisting the selection of the most cost-effective options for carbon capture and storage. To demonstrate the applicability of the methodology a case study has been carried out to illustrate the possible impact of technology improvements and market development. The case study confirms that the CO₂-quota price to a large extent influence the project economy and dominates over potential technology improvements. To be economic feasible, the studied chains injecting the CO₂ in oil reservoirs for increased oil production require a CO₂-quota price in the range of 20–27 €/tonne CO₂, depending on the technology breakthrough. For the chains based on CO₂ storage in saline aquifers, the corresponding CO₂-quota price varies up to about 40 €/tonne CO₂.     

Economics and GHG emission reduction of a PLA bio-refinery system—Combining bottom-up analysis with price elasticity effects

This paper analyses energy savings, GHG emission reductions and costs of bio-refinery systems for polylactic acid (PLA) production. The systems comprise ‘multi-functional’ uses of biomass resources, i.e. use of agricultural residues for energy consumption, use of by-products, and recycling and waste-to-energy recovery of materials. We evaluate the performance of these systems per kg of bio-based polymer produced and per ha of biomass production. The evaluation is done using data of Poland assuming that biomass and PLA production is embedded in a European energy and material market. First, the performance of different bio-refinery systems is investigated by means of a bottom-up chain analysis. Second, an analysis is applied that derives market prices of products and land depending on the own-price elasticity of demand. Thus, the costs of bio-refinery systems depending on the demand of land and material are determined. It is found that all PLA bio-refinery systems considered lead to net savings of non-renewable energy consumption of 70–220 GJ/(ha yr) and net GHG emission reductions of 3–17 Mg CO_2eq/(ha yr). Most of these PLA bio-refinery systems lead to net costs for the overall system of up to 4600 €/(ha yr). PLA production from short rotation wood leads to net benefits of about 1100 €/(ha yr) if a high amount of a high value product, i.e. fibres, is produced. Multi-functionality is necessary to ensure the viability of PLA bio-refinery systems from biomass with regard to energy savings and GHG emission reduction. However, the multi-functional use of biomass does not contribute much to overall incomes. Multifunctional biomass use – especially the use of biomass residues for energy consumption – contributes significantly to savings of non-renewable energy sources. Own-price elasticity of the demand for materials influences the overall costs of the bio-refinery system strongly. The own-price elasticity of land demand markets could become important if bio-refineries are introduced on a large scale.     

Energy and carbon dioxide intensity of Thailand's steel industry and greenhouse gas emission projection toward the year 2050

The purpose of this article is to study the energy and carbon dioxide intensities of Thailand's steel industry and to propose greenhouse gas emission trends from the year 2011 to 2050 under plausible scenarios. The amount of CO₂ emission from iron and steel production was calculated using the 2006 Intergovernmental Panel on Climate Change (IPCC) guidelines in the boundary of production process (gate to gate). The results showed that energy intensity of semi-finished steel product was 2.84 GJ/t semi-finished steel and CO₂ intensity was 0.37 tCO_2eq/t semi-finished steel. Energy intensity of steel finishing process was 1.86 GJ/t finished steel and CO₂ intensity was 0.16 tCO_2eq/t finished steel. Using three plausible scenarios from Thailand's steel industry, S1: without integrated steel plant (baseline scenario), S2: with a traditional integrated BF–BOF route and S3: with an alternative integrated DR-EAF route; the Greenhouse Gas emissions from the year 2011 to 2050 were projected. In 2050, the CO₂ emission from S1 (baseline scenario) was 4.84 million tonnes, S2 was 21.96 million tonnes increasing 4.54 times from baseline scenario. The CO₂ emission from S3 was 7.12 million tonnes increasing 1.47 times from baseline scenario.     

Life cycle assessment of natural gas combined cycle power plant with post-combustion carbon capture,transport and storage

Hybrid life cycle assessment has been used to assess the environmental impacts of natural gas combined cycle (NGCC) electricity generation with carbon dioxide capture and storage (CCS). The CCS chain modeled in this study consists of carbon dioxide (CO₂) capture from flue gas using monoethanolamine (MEA), pipeline transport and storage in a saline aquifer.Results show that the sequestration of 90% CO₂ from the flue gas results in avoiding 70% of CO₂ emissions to the atmosphere per kWh and reduces global warming potential (GWP) by 64%. Calculation of other environmental impacts shows the trade-offs: an increase of 43% in acidification, 35% in eutrophication, and 120–170% in various toxicity impacts. Given the assumptions employed in this analysis, emissions of MEA and formaldehyde during capture process and generation of reclaimer wastes contributes to various toxicity potentials and cause many-fold increase in the on-site direct freshwater ecotoxicity and terrestrial ecotoxicity impacts. NO_x from fuel combustion is still the dominant contributor to most direct impacts, other than toxicity potentials and GWP. It is found that the direct emission of MEA contribute little to human toxicity (HT < 1%), however it makes 16% of terrestrial ecotoxicity impact. Hazardous reclaimer waste causes significant freshwater and marine ecotoxicity impacts. Most increases in impact are due to increased fuel requirements or increased investments and operating inputs.The reductions in GWP range from 58% to 68% for the worst-case to best-case CCS system. Acidification, eutrophication and toxicity potentials show an even large range of variation in the sensitivity analysis. Decreases in energy use and solvent degradation will significantly reduce the impact in all categories.     

Feasibility of storing CO2 in the Utsira formation as part of a long term Dutch CCS strategy: An evaluation based on a GIS/MARKAL toolbox

This study provides insight into the feasibility of a CO₂ trunkline from the Netherlands to the Utsira formation in the Norwegian part of the North Sea, which is a large geological storage reservoir for CO₂. The feasibility is investigated in competition with CO₂ storage in onshore and near-offshore sinks in the Netherlands. Least-cost modelling with a MARKAL model in combination with ArcGIS was used to assess the cost-effectiveness of the trunkline as part of a Dutch greenhouse gas emission reduction strategy for the Dutch electricity sector and CO₂ intensive industry. The results show that under the condition that a CO₂ permit price increases from €25 per tCO₂ in 2010 to €60 per tCO₂ in 2030, and remains at this level up to 2050, CO₂ emissions in the Netherlands could reduce with 67% in 2050 compared to 1990, and investment in the Utsira trunkline may be cost-effective from 2020–2030 provided that Belgian and German CO₂ is transported and stored via the Netherlands as well. In this case, by 2050 more than 2.1 GtCO₂ would have been transported from the Netherlands to the Utsira formation. However, if the Utsira trunkline is not used for transportation of CO₂ from Belgium and Germany, it may become cost-effective 10 years later, and less than 1.3 GtCO₂ from the Netherlands would have been stored in the Utsira formation by 2050. On the short term, CO₂ storage in Dutch fields appears more cost-effective than in the Utsira formation, but as yet there are major uncertainties related to the timing and effective exploitation of the Dutch offshore storage opportunities.     

Environmental benefits from the use of the residual biomass in nurseries

Every year, nurseries waste about 40 t of residual biomass for each ha of potted plants cultivation. The European nursery sector deals with about 90,000 ha of cultivated land and 120,000 ha of nurseries, with a turnover of 19.8 billion Euros in 2011. In recent years, a number of Italian projects highlighted that GHG (greenhouse gas) emissions for the nursery sector range between 37 tCO₂eq/ha/year and 45 tCO₂eq/ha/year for potted plants, mainly due to the consumption of electric energy, plastics and peat. Moreover, other studies analyse the impacts associated to nurseries, recommending best practices for energy reductions and waste recycle or reuse. Therefore, the present work focused its attention to the possible environmental benefits associated to the reuse of residues (wood and substrate) of potted plants that are discarded from the nursery production chain. GHG emissions and fossil energy requirement were quantified by considering the CO₂eq (CO₂ equivalent) and the CER (cumulative energy requirement) respectively, in order to assess the environmental impacts of two different scenarios proposed for the materials recovery. Final results highlighted that the solutions which are able to recover the substrate and the wood allow impact reductions compared to landfill disposal. In particular, the scenario consisting in the immediate separation of the substrate from the root-plant system and the successive chipping of wood for energetic reuse, allows higher savings than those obtainable through shredding and subsequent wind separation. Moreover, for what concerns the CO₂eq, an adequate use of the residual biomass make it possible to compensate the GHG emissions of the nurseries up to 15%.     

CO2 capture for refineries,a practical approach

This paper evaluates the opportunities and associated costs for post-combustion capture at a world-scale complex refinery. It is concluded that it is technically feasible to apply post-combustion capture at such a refinery. The costs for capture and sequestration from a gasifier are calculated to be lowest at about 30 Euro per ton; this process currently already produces a concentrated CO₂ stream. Next, the CO₂ source most suited for capture appears to be a combined stack, but there are a number of other sources that may be targeted at comparable costs. In total these sources may form about 40% of the overall refinery emissions. Our evaluations show the costs of capture from such sources based on available amine technology will be in the range of 90–120 Euro per ton, which is about 3–4 times higher than the current carbon trading values. The capture of CO₂ from a large amount of smaller CO₂ sources will bring along even much higher costs. A high-level study of the CO₂ emissions profile of a number of Shell refineries shows that, typically, up to 50% of the emitted CO₂ may be captured at similar costs. About 10–20% of concentrated CO₂ associated with hydrogen manufacturing may be captured at lower costs. The remainder of emitted dilute CO₂ will bring along significantly higher costs. Based on this study, it is concluded for the justification of the implementation of post-combustion capture at refineries, either a significant increase in carbon trading values, mandatory regulations, or a major technological break-through is required.     

Life cycle assessment of a pulverized coal power plant with post-combustion capture, transport and storage of CO2

In this study the methodology of life cycle assessment has been used to assess the environmental impacts of three pulverized coal fired electricity supply chains with and without carbon capture and storage (CCS) on a cradle to grave basis. The chain with CCS comprises post-combustion CO₂ capture with monoethanolamine, compression, transport by pipeline and storage in a geological reservoir. The two reference chains represent sub-critical and state-of-the-art ultra supercritical pulverized coal fired electricity generation. For the three chains we have constructed a detailed greenhouse gas (GHG) balance, and disclosed environmental trade-offs and co-benefits due to CO₂ capture, transport and storage. Results show that, due to CCS, the GHG emissions per kWh are reduced substantially to 243 g/kWh. This is a reduction of 78 and 71% compared to the sub-critical and state-of-the-art power plant, respectively. The removal of CO₂ is partially offset by increased GHG emissions in up- and downstream processes, to a small extent (0.7 g/kWh) caused by the CCS infrastructure. An environmental co-benefit is expected following from the deeper reduction of hydrogen fluoride and hydrogen chloride emissions. Most notable environmental trade-offs are the increase in human toxicity, ozone layer depletion and fresh water ecotoxicity potential for which the CCS chain is outperformed by both other chains. The state-of-the-art power plant without CCS also shows a better score for the eutrophication, acidification and photochemical oxidation potential despite the deeper reduction of SO_x and NO_x in the CCS power plant. These reductions are offset by increased emissions in the life cycle due to the energy penalty and a factor five increase in NH₃ emissions.     

Effect of synthesis parameters on single gas permeation through T-type zeolite membranes

In this research, nanoporous zeolite T membranes were synthesized at three levels of synthesis temperature: 100, 120 and 140 °C and synthesis time: 15, 30 and 50 h and characterized by gas permeation. Effects of synthesis parameters on CO₂ and CH₄ permeances and CO₂/CH₄ ideal separation factors were studied. All experiments were conducted at 1 bar feed pressure and 30 °C module temperature. Normally, it is anticipated that increasing synthesis temperature and synthesis time increase gas permeances and consequently decrease ideal separation factor. This prediction was not observed in the case of synthesis temperature increase from 100 to 120 °C as well as synthesis time increase from 15 to 30 h, due to the dual effect of increasing synthesis temperature and synthesis time on gas permeances and ideal separation factor. More zeolites are deposited and larger crystals are formed at higher synthesis temperatures and times. Forming the larger crystals accelerates the rate of zeolite layer integration, which is responsible for gas separation, in one hand and reduces the density of deposited zeolite layer on the support, due to the formation of more voids, on the other hand. In terms of maximizing the CO₂/CH₄ ideal separation factor, medium synthesis temperature and synthesis time (120 °C and 30 h) can be selected, however, maximum gas permeances are obtained at low levels of synthesis temperature and time (100 °C and 15 h). According to the ranges of gas permeances (10⁻¹¹ to 10⁻⁶ mol/m² s Pa) and CO₂/CH₄ ideal separation factors (1.4–70.3), it is concluded that the zeolite T membranes synthesized at optimum conditions can be employed for membrane separation of CO₂/CH₄ mixtures.     

Model prediction on the rise of pCO2 in uniform flows by leakage of CO2 purposefully stored under the seabed

A numerical study was conducted to predict pCO₂ change in the ocean on a continental shelf by the leakage of CO₂, which is originally stored in the aquifer under the seabed, in the case that a large fault connects the CO₂ reservoir and the seabed by an earthquake or other diastrophism. The leakage rate was set to be 6.025 × 10⁻⁴ kg/m²/sec from 2 m × 100 m fault band, which corresponds to 3800 t-CO₂/year, referring to the monitored seepage rate from an existing EOR field. The target space in this study was limited to the ocean above the seabed, the depth of which was 200 or 500 m. The computational domain was idealistically rectangular with the seabed fault-band perpendicular to the uniform flow. The CO₂ takes a form of bubbles or droplets, depending on the depth of water, and their behaviour and dissolution were numerically simulated during their rise in seawater flow. The advection–diffusion of dissolved CO₂ was also simulated. As a result, it was suggested that the leaked CO₂ droplets/bubbles all dissolve in the seawater before spouting up to the atmosphere, and that the increase in pCO₂ in the seawater was smaller than 500 μ atm.     

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.     

Post-combustion CO2-capture from coal-fired power plants: Preliminary evaluation of an integrated chemical absorption process with piperazine-promoted potassium carbonate

The simulation tool ASPEN Plus^® is used to model the full CO₂-capture process for chemical absorption of CO₂ by piperazine-promoted potassium carbonate (K₂CO₃/PZ) and the subsequent CO₂-compression train. Sensitivity analysis of lean loading, desorber pressure and CO₂-capture rate are performed for various solvent compositions to evaluate the optimal process parameters. EbsilonProfessional^® is used to model a 600 MW_el (gross) hard coal-fired power plant. Numerical equations for power losses due to steam extraction for solvent regeneration are derived from simulation runs. The results of the simulation campaigns are used to find the process parameters that show the lowest specific power loss. Subsequently, absorber and desorber columns are dimensioned to evaluate investment costs for these main components of the CO₂-capture process. Regeneration heat duty, net efficiency losses and column investment costs are then compared to the reference case of CO₂-capture by monoethanolamine (MEA).CO₂-capture by piperazine-promoted potassium carbonate with subsequent CO₂-compression to 110 bar shows energetic advantages over the reference process which uses MEA. Additionally, investment costs for the main components in the CO₂-capture process (absorber and desorber columns) are lower due to the enhanced reaction kinetics of the investigated K₂CO₃/PZ solvent which leads to smaller component sizes.     

Gas conditioning—The interface between CO2 capture and transport

Gas conditioning is commonly referred to as the required processing for a produced natural gas to achieve transport and sales specifications. In this paper, gas conditioning as the processing required in the interface between CO₂ capture and transport is studied for nine different natural gas fired power plant concepts and three different CO₂ transport processes. Conditioning processes for both pipeline and ship transport are described and an enhanced process for volatile removal is developed. The energy requirement for the conditioning processes is normally between 90 and 120 kWh/tonne CO₂; however, this depends on the pressure and composition of the captured CO₂-rich stream. The loss of CO₂ in the water purge is small for most capture processes. The waste streams from the gas conditioning processes can contain large amounts of CO₂ and should therefore be further processed or reintroduced at an appropriate point upstream in the capture or gas conditioning process if possible. The integration benefit may vary depending on the composition of the CO₂-rich stream. It could be particularly interesting for processes with “innovative reactors” (membranes, sorbents, chemical looping) to integrate CO₂ capture and gas conditioning.     

Water/acid gas interfacial tensions and their impact on acid gas geological storage

Acid gas geological disposal is a promising process to reduce CO₂ atmospheric emissions and an environment-friendly and economic alternative to the transformation of H₂S into sulphur by the Claus process. Acid gas confinement in geological formations is to a large extent controlled by the capillary properties of the water/acid–gas/caprock system, because a significant fraction of the injected gas rises buoyantly and accumulates beneath the caprock. These properties include the water/acid gas interfacial tension (IFT), to which the so-called capillary entry pressure of the gas in the water-saturated caprock is proportional. In this paper we present the first ever systematic water/acid gas IFT measurements carried out by the pendant drop technique under geological storage conditions. We performed IFT measurements for water/H₂S systems over a large range of pressure (up to P = 15 MPa) and temperature (up to T = 120 °C). Water/H₂S IFT decreases with increasing P and levels off at around 9–10 mN/m at high T (≥70 °C) and P (>12 MPa). The latter values are around 30–40% of water/CO₂ IFTs, and around 20% of water/CH₄ IFTs at similar T and P conditions. The IFT between water and a CO₂ + H₂S mixture at T = 77 °C and P > 7.5 MPa is observed to be approximately equal to the molar average IFT of the water/CO₂ and water/H₂S binary mixtures. Thus, when the H₂S content in the stored acid gas increases the capillary entry pressure decreases, together with the maximum height of acid gas column and potential storage capacity of a given geological formation. Hence, considerable attention should be exercised when refilling with a H₂S-rich acid gas a depleted gas reservoir, or a depleted oil reservoir with a gas cap: in the case of hydrocarbon reservoirs that were initially (i.e., at the time of their discovery) close to capillary leakage, acid gas leakage through the caprock will inevitably occur if the refilling pressure approaches the initial reservoir pressure.     

CO2 transportation for carbon capture and storage: Sublimation of carbon dioxide from a dry ice bank

Climate change is being caused by greenhouse gases such as carbon dioxide (CO₂). Carbon capture and storage (CCS) is of interest to the scientific community as one way of achieving significant global reductions of atmospheric CO₂ emissions in the medium term. CO₂ would be captured from large stationary sources such as power plants and transported via pipelines under high pressure conditions to underground storage. If a downward leakage from a surface transportation system module occurs, the CO₂ would undergo a large temperature reduction and form a bank of “dry ice” on the ground surface; the sublimation of the gas from this bank represents an area source term for subsequent atmospheric dispersion, with an emission rate dependent on the energy balance at the bank surface. Gaseous CO₂ is denser than air and tends to remain close to the surface; it is an asphyxiant, a cerebral vasodilator and at high concentrations causes rapid circulatory insufficiency leading to coma and death. Hence a subliming bank of dry ice represents safety hazard. A model is presented for evaluating the energy balance and sublimation rate at the surface of a solid frozen CO₂ bank under different environmental conditions. The results suggest that subliming gas behaves as a proper dense gas (i.e. it remains close to the ground surface) only for low ambient wind speeds.     

Evaluating geological sequestration of CO2 in bituminous coals: The southern Sydney Basin,Australia as a natural analogue

Carbon dioxide contents of coals in the Sydney Basin vary both aerially and stratigraphically. In places, the coal seam gas is almost pure CO₂ that was introduced from deep magmatic sources via faults and replaced pre-existing CH₄. In some respects this process is analogous to sequestration of anthropogenic CO₂. Laboratory studies indicate that CO₂:CH₄ storage capacity ratios for Sydney Basin coals are up to ∼2 and gas diffusivity is greater for CO₂ by a factor of up to 1.5.Present-day distribution of CO₂ in the coals is controlled by geological structure, depth and a combination of hydrostatic and capillary pressures. Under present-day P–T conditions, most of the CO₂ occurs in solution at depths greater than about 650 m; at shallower depths, larger volumes of CO₂ occur in gaseous form and as adsorbed molecules in the coal due to rapidly decreasing CO₂ solubility. The CO₂ has apparently migrated up to structural highs and is concentrated in anticlines and in up-dip sections of monoclines and sealing faults. CO₂ sequestered in coal measure sequences similar to those of the Sydney Basin may behave in a similar way and, in the long term, equilibrate according to the prevailing P–T conditions.In situ CO₂ contents of Sydney Basin coals range up to 20 m³/t. Comparisons of adsorption isotherm data measured on ground coal particles with in situ gas contents of Sydney Basin coals indicate that the volumes of CO₂ stored do not exceed ∼60% of the total CO₂ storage capacity. Therefore, the maximum CO₂ saturation that may be achieved during sequestration in analogous coals is likely to be considerably lower than the theoretical values indicated by adsorption isotherms.     

Carbon dioxide storage capacity in uneconomic coal beds in Alberta,Canada: Methodology,potential and site identification

Methodology is presented for a first-order regional-scale estimation of CO₂ storage capacity in coals under sub-critical conditions, which is subsequently applied to Cretaceous-Tertiary coal beds in Alberta, Canada. Regions suitable for CO₂ storage have been defined on the basis of groundwater depth and CO₂ phase at in situ conditions. The theoretical CO₂ storage capacity was estimated on the basis of CO₂ adsorption isotherms measured on coal samples, and it varies between ∼20 kt CO₂/km² and 1260 kt CO₂/km², for a total of approximately 20 Gt CO₂. This represents the theoretical storage capacity limit that would be attained if there would be no other gases present in the coals or they would be 100% replaced by CO₂, and if all the coals will be accessed by CO₂. A recovery factor of less than 100% and a completion factor less than 50% reduce the theoretical storage capacity to an effective storage capacity of only 6.4 Gt CO₂. Not all the effective CO₂ storage capacity will be utilized because it is uneconomic to build the necessary infrastructure for areas with low storage capacity per unit surface. Assuming that the economic threshold to develop the necessary infrastructure is 200 kt CO₂/km², then the CO₂ storage capacity in coal beds in Alberta is greatly reduced further to a practical capacity of only ∼800 Mt CO₂.