We performed a consistent comparison of state-of-the-art and advanced electricity and hydrogen production technologies with CO 2 capture using coal and natural gas, inspired by the large number of studies, of which the results can in fact not be compared due to specific assumptions made. After literature review, a standardisation and selection exercise has been performed to get figures on conversion efficiency, energy production costs and CO 2 avoidance costs of different technologies, the main parameters for comparison. On the short term, electricity can be produced with 85-90% CO 2 capture by means of NGCC and PC with chemical absorption and IGCC with physical absorption at 4.7-6.9 Vct/kWh, assuming a coal and natural gas price of 1.7 and 4.7 V/GJ. CO 2 avoidance costs are between 15 and 50 V/t CO 2 for IGCC and NGCC, respectively. On the longer term, both improvements in existing conversion and capture technologies are foreseen as well as new power cycles integrating advanced turbines, fuel cells and novel (high-temperature) separation technologies. Electricity production costs might be reduced to 4.5-5.3 Vct/kWh with advanced technologies. However, no clear ranking can be made due to large uncertainties pertaining to investment and O&M costs. Hydrogen production is more attractive for low-cost CO 2 capture than electricity production. Costs of large-scale hydrogen production by means of steam methane reforming and coal gasification with CO 2 capture from the shifted syngas are estimated at 9.5 and 7 V/GJ, respectively. Advanced autothermal reforming and coal gasification deploying ion transport membranes might further reduce production costs to 8.1 and 6.4 V/GJ. Membrane reformers enable small-scale hydrogen production at nearly 17 V/GJ with relatively low-cost CO 2 capture. q

Abstract. CO 2 capture and storage (CCS) in geological reservoirs may be part of a strategy to reduce global anthropogenic CO 2 emissions. Insight in the risks associated with underground CO 2 storage is needed to ensure that it can be applied as safe and effective greenhouse mitigation option. This paper aims to give an overview of the current (gaps in) knowledge of risks associated with underground CO 2 storage and research areas that need to be addressed to increase our understanding in those risks. Risks caused by a failure in surface installations are understood and can be minimised by risk abatement technologies and safety measures. The risks caused by underground CO 2 storage (CO 2 and CH 4 leakage, seismicity, ground movement and brine displacement) are less well understood. Main R&D objective is to determine the processes controlling leakage through/along wells, faults and fractures to assess leakage rates and to assess the effects on (marine) ecosystems. Although R&D activities currently being undertaken are working on these issues, it is expected that further demonstration projects and experimental work is needed to provide data for more thorough risk assessment.

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The membrane reactor is a novel technology for the production of hydrogen from natural gas. It promises economic small-scale hydrogen production, e.g. at refuelling stations and has the potential of inexpensive CO 2 separation. Four configurations of the membrane reactor have been modelled with Aspen plus to determine its thermodynamic and economic prospects. Overall energy efficiency is 84% HHV without H 2 compression (78% with compression up to 482 bar). The modelling results also indicate that by using a sweep gas, the membrane reactor can produce a reformer exit stream consisting mainly of CO 2 and H 2 O (490% mol) suited for CO 2 sequestration after water removal with an efficiency loss of only 1% pt. Reforming with a 2 MW membrane reactor (250 unit production volume) costs 14 $/GJ H 2 including compression, which is more expensive than conventional steam reforming+compression (12 $/GJ). It does, however, promise a cheap method of CO 2 separation, 14 $/t CO 2 captured, due to the high purity of the exit stream. The well-towheel chain of the membrane reactor has been compared to centralised steam reforming to assess the trade-off between production scale and the construction of a hydrogen and a CO 2 distribution infrastructure. If the scale of centralised hydrogen production is below 40 MW, the trade-off could be favourable for the membrane reactor with small-scale CO 2 capture (18 $/GJ including H 2 storage, dispensing and CO 2 sequestration for 40 MW SMR versus 19 $/GJ for MR). The membrane reactor might become competitive with conventional steam reforming provided that thin membranes can be combined with high stability and a cheap manufacturing method for the membrane tubes. Thin membranes, industrial utility prices and larger production volumes (i.e. technological learning) might reduce the levelised hydrogen cost of the membrane reactor at the refuelling station to less than 14 $/GJ including CO 2 sequestration cost, below that of large-scale H 2 production with CO 2 sequestration

Promising electricity and hydrogen production chains with CO 2 capture, transport and storage (CCS) and energy carrier transmission, distribution and end-use are analysed to assess (avoided) CO 2 emissions, energy production costs and CO 2 mitigation costs. For electricity chains, the performance is dominated by the impact of CO 2 capture, increasing electricity production costs with 10-40% up to 4.5-6.5 hct/kWh. CO 2 transport and storage in depleted gas fields or aquifers typically add another 0.1-1 hct/kWh for transport distances between 0 and 200 km. The impact of CCS on hydrogen costs is small. Production and supply costs range from circa 8 h/GJ for the minimal infrastructure variant in which hydrogen is delivered to CHP units, up to 20 h/GJ for supply to households. Hydrogen costs for the transport sector are between 14 and 16 h/GJ for advanced large-scale coal gasification units and reformers, and over 20 h/GJ for decentralised membrane reformers. Although the CO 2 price required to induce CCS in hydrogen production is low in comparison to most electricity production options, electricity production with CCS generally deserves preference as CO 2 mitigation option. Replacing natural gas or gasoline for hydrogen produced with CCS results in mitigation costs over 100 h/t CO 2 , whereas CO 2 in the power sector could be reduced for costs below 60 h/t CO 2 avoided. r